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Power Engineering is the flagship media sponsor for 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: pe@pennwell.com World Wide Web: http://www.power-eng.com CHIEF EDITOR — Russell Ray (918) 832-9368 russellr@pennwell.com ASSOCIATE EDITOR — Sharryn Dotson (918) 832-9339 sharrynd@pennwell.com

FEATURES 119 VOLUME

Large-Scale 12 Solar on the Rise

ASSOCIATE EDITOR — Tim Miser (918) 831-9492 tmiser@pennwell.com CONTRIBUTING EDITOR—Brad Buecker CONTRIBUTING EDITOR—Brian Schimmoller CONTRIBUTING EDITOR—Robynn Andracsek CONTRIBUTING EDITOR—Wayne Barber (540) 252-2137 wayneb@pennwell.com CONTRIBUTING EDITOR—Barry Cassell (804) 815-9186 barryc@pennwell.com GRAPHIC DESIGNER — Deanna Priddy Taylor (918) 832-9378 deannat@pennwell.com SUBSCRIBER SERVICE P.O. Box 3264, Northbrook, IL 60065 Phone: (847) 763-9540 E-mail: poe@halldata.com MARKETING MANAGER — Rachel Campbell (918) 831-9576 rachelc@pennwell.com SENIOR VICE PRESIDENT, NORTH AMERICAN POWER GENERATION GROUP — Richard Baker (918) 831-9187 richardb@pennwell.com

The cost of generating electricity from utility-scale solar power has plummeted in recent years, but the possible end of federal investment tax credits threatens to temper an otherwise sunny outlook for the industry. Find out what the future holds for solar in North America.

Circulating Fluidized Bed Scrubber vs. Spray Dryer Absorber

In response to more stringent air emissions regulations, utilities are under pressure to add flue gas desulfurization to their coal-fired units. Power Engineering investigates the differences between state-of-the-art circulating fluidized bed scrubbers and the latest advanced spray dryer absorber designs.

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316(b): One Year Later

As the one-year anniversary of the EPA’s newest 316(b) regulations approaches, Power Engineering examines the details of the rule and how power producers can best meet the revised mandates.

Power Engineering

Turbine Oils: A Key Factor in System Reliability

Turbine lubricants must perform under the hostile conditions of heat, friction, and chemical degradation. Learn how the right mix of oil and additives, combined with a disciplined program of testing and maintenance, can prevent unwanted varnish and forestall premature equipment wear.

Maintaining Maximum Efficiency in Power Generation Units

Pressure to lower industrial carbon dioxide emissions continues to foster increased interest in improved efficiency at steam generating facilities. Read about some of the issues operators face in their quest for more efficient plants.

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Improving the Flexibility and Efficiency of a Gas Turbine-Based Distributed Power Plant

By building smaller, more flexible gas-fired power plants closer to actual load centers, network operators can better satisfy their customers’ power demands. Learn how an efficient and flexible distributed generation model can help power producers meet the challenges of today’s power landscape.

CHAIRMAN — Frank T. Lauinger PRESIDENT/CHIEF EXECUTIVE OFFICER — Robert F. Biolchini

CIRCULATION MANAGER — Linda Thomas PRODUCTION MANAGER — Katie Noftsger

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OPINION

What You Need to Know About the Clean Power Plan BY RUSSELL RAY, CHIEF EDITOR

he minute the Obama administration unveiled its final plan to cut greenhouse gas emissions from U.S. power plants, opponents launched the first of many legal efforts to kill what some have described as the most prejudicial regulation ever proposed by the U.S. Environmental Protection Agency (EPA). The Clean Power Plan calls for sweeping new requirements to cut carbon dioxide (CO2) emissions 32 percent below 2005 levels by 2030. The rule will require a massive restructuring of the power sector. It will decimate coal by establishing unattainable CO2 standards for coal plants. It does nothing to promote the use of cleaner-burning natural gas, but it will stimulate the deployment of intermittent wind and solar power with new incentives. What’s more, it will require states to spend billions to comply with a rule that may ultimately be vacated by the U.S. Supreme Court. Several states have asked a federal appeals court to stay the controversial plan until the courts decide whether the EPA has the authority to force states to limit CO2 from U.S. power plants. More states are expected to join a lawsuit challenging the rule, a case that will likely end years from now at the Supreme Court. What are the plaintiffs’ chances of winning the case against the EPA? Better than average, I would say. On June 29, the high court struck down the EPA’s Mercury and Air Toxics Standard, better known as the MATS rule, which established the first limits on mercury, arsenic and acid-gas emissions from coal-fired power plants. 2

The final MATS rule was issued back in 2012 and became effective earlier this year. However, the Supreme Court remanded the rule to the D.C. Circuit Court, saying the EPA failed to consider the $9.6 billion cost of implementing the new rule when drafting it. The industry spent billions to comply with the MATS rule, which now faces the possibility of being vacated. How the Supreme Court will rule on the Clean Power Plan is anyone’s guess, but its ruling on the MATS rule is compelling evidence the high court may reject the plan. The states’ case against the Clean Power Plan centers on the EPA’s authority to regulate greenhouse gas emissions from power plants under section 111(d) of the Clean Air Act (CAA). The states contend power plant emissions are already regulated under section 112 of the CAA. The CAA prohibits the EPA from regulating power plant emissions under more than one section of the law. What’s more, opponents of the plan argue the EPA is already regulating power plant emissions under the MATS rule and, thus, does not have the authority to regulate such emissions under section 111(d) of the CAA. However, if the MATS rule is vacated by the D.C. Circuit Court, that legal argument will vanish. “That may undermine one of the key legal challenges to the EPA’s Clean Power Plan,” said Andy Byers, associate vice president at Black & Veatch. “A lot of folks are speculating the EPA may go back to the circuit court and ask them to overturn their (MATS) rule.”

In another bizarre twist, the CO2 limit for existing plants is 1,307 pounds per megawatt-hour while the CO2 limit for new plants is 1,400 pounds per MWh. Under the final rule, the standard for an existing plant is more stringent than the standard for a brand new plant. What gives? The new standards can’t be achieved without installing a carbon capture and storage system, an expensive and questionable technology. “We just commissioned the most efficient coal-fired power plant in the country in Arkansas and its CO2 emissions are just under 1,800 pounds per megawatt-hour,” said Mark McCullough, executive vice president of Generation at American Electric Power. The new CO2 standards are among a host of new, costly requirements faced by coal-fired power plants. The new rules mean as much as 90,000 MW of coal-fired generation will be retired between now and 2040. Most of those retirements are expected to be achieved by 2020. The only real option for replacing that dispatchable output is power fueled with natural gas. “The risk profile of coal and nuclear, from a utility perspective, is just too high,” McCullough said. But too much reliance on natural gas could lead to serious economic and security issues for the nation’s power sector, McCullough said. “Absence of diversity is a recipe for a big problem,” he said. If you have a question or a comment, contact me at russellr@pennwell.com. Follow me on Twitter @RussellRay1. www.power-eng.com

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INDUSTRY NEWS

PJM Increases Payments to Power Producers 37 Percent PJM Interconnection, the largest electric grid in the U.S., will increase payments to power generators 37 percent. The company said the increase will begin in June 2018, and will be $164.77 per megawatt (MW) per day, as determined in a capacity auction held last month. The price is almost $45 above the previous 12 months reached in an auction last year. Precipitating the increase was a decision by federal regulators to allow PJM to penalize generators that fail to supply promised power. The decision was intended to prevent unplanned shutdowns and fuel shortages, like those that greatly inflated prices during the winter of 2014. Capacity costs were set at higher levels for two regions because of supply constraints. The eastern mid-Atantic region, including New Jersey, Delaware and Pennsylvania, finalized a price of $225.42/MW/day, while prices in Exelon Corp.’s ComEd utility territory rose to $215.Under the new rules, the grid operator can impose penalties of about $2,800 per megawatt-hour on generators who fail to deliver promised power during emergency hours.

Exelon-Pepco Merger in Doubt After Regulators Reject Proposal The D.C. Public Service Commission last month rebuffed a multi-billion dollar proposed merger between power companies Exelon and Pepco. The three-member commission unanimously rejected the $6.8 billion merger. Chicago-based Exelon announced in April 2014 plans to acquire Washington-based Pepco Holdings. The deal would have created the largest electric and gas utility in the region with about 10 million customers in cities including Baltimore, Chicago, Philadelphia 4

and Washington. Despite garnering the approval of several surrounding states, Exelon and Pepco failed to reach settlements with regulators in Washington D.C. Chairwoman Betty Ann Kane said in a statement the companies failed to show the merger was a benefit to the public. “The evidence in the record is that sale and change in control proposed in the merger would move us in the opposite direction,” Kane said. The companies expressed disappointment in the decision and said the commission did not recognize the benefits of the merger.

Excel Energy Cuts GHG Emissions 20 Percent

Xcel Energy has become the first utility in the nation to register nearly a decade’s worth of greenhouse gas emissions data with The Climate Registry, a nonprofit organization that operates voluntary and compliance greenhouse gas reporting programs throughout the world. The company pledged to begin reducing emissions in 2005, according to Xcel Energy Vice President Frank Prager. In the years since, the utility has seen more than a 20-percent reduction in carbon dioxide emissions and is on track to achieve a 30-percent reduction companywide by 2020. Xcel Energy reached Climate Registered status by measuring and reporting the company’s emissions from 2005 to 2011. The data was then verified by a third party.

The company’s emissions from 2012 to 2014 are being verified and registered with The Climate Registry.

Obama Announces $1 Billion in DOE Initiatives President Obama last month announced more than $1 billion in initiatives promoting clean energy. The president’s Clean Power Plan permits the Department of Energy’s Loan Programs Office to guarantee up to $1 billion for commercial-scale distributed energy projects like rooftop solar, smart grid technology and methane capture for oil and gas wells. Distributed energy technologies reduce greenhouse gas emissions while strengthening energy security and creating economic opportunity, but projects often encounter roadblocks when it comes to lenders who are unwilling to take on the risk of a new technology. Additionally, the DOE is awarding $24 million through the Advanced Research Projects Agency – Energy for 11 high-performance solar power projects aimed at lowering the cost and improving the performance of solar photovoltaic power systems.

GE Signs its Largest Battery Storage Deal to Date GE announced it will provide Coachella Energy Storage Partners (CESP) with a 30-MW battery energy storage system as part of CESP’s supply contract with the Imperial Irrigation District (IID). Representing GE’s largest energy storage project to date, the plant will be built in California’s Imperial Valley, 100 miles east of San Diego. The facility will aid grid flexibility and increase reliability on the IID network by providing solar ramping, frequency regulation, power balancing, and black start capability for an adjacent gas turbine. GE will provide CESP with an integrated energy storage solution, configured www.power-eng.com

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using GE’s Mark VI plant controls, GE Brilliance MW inverters, GE Prolec transformers, medium-voltage switchgear, and advanced lithium ion batteries housed in a GE purpose-built enclosure. The plant will be operated by ZGlobal, an engineering collaborator with CESP, for the first 18 months, after which control will transfer to the IID. Construction is expected to begin early next year, with commercial operation scheduled for the third quarter of 2016.

NRC Issues Corrective Actions Against Millstone 2 Nuclear Unit Dominion is implementing a range of corrective actions at the Millstone Unit 2 nuclear plant in Connecticut to address violations. In September 2011, the NRC became aware that Dominion had submitted requests for approval of amendments to the Millstone 2 operating license that were incomplete and inaccurate. The requests were to modify requirements for Unit 2’s charging pumps and irradiated fuel decay time. NRC’s Office of Investigations began an investigation the following November to determine if there was any wrongdoing. On April 29, 2015, NRC notified Dominion that the violations were considered for escalated enforcement. The first violation was for a willful violation for changes made to the plant’s Updated Final Safety Analysis Report, without a license amendment, that removed credit for a specific type of safety-related pump in the mitigation of a plant accident. The second violation was a non-willful violation for a failure to provide complete and accurate information to the NRC pertaining to the changes. The third violation, related to the utility’s failure to obtain a license amendment prior to making changes related to spent fuel pool heatload analysis, was not considered for escalated enforcement. 6

Louisiana Regulators Approve Merger of Entergy Utilities The Louisiana Public Service Commission approved the merger of Entergy Louisiana LLC and Entergy Gulf States Louisiana LLC into a single utility. The new utility will operate under the name Entergy Louisiana LLC after the deal closes Oct. 1. It will have over $16.5 billion in assets and 66,194 GWh in combined sales. Louisiana’s utilities provide electricity to more than one million customers, and natural gas service to over 93,000 customers in the greater Baton Rouge area. The merged company will be a unit of Entergy Corp.

GE’s Gas Turbine Surpasses 75 Million Operating Hours

GE’s LM2500 aeroderivative gas turbine has reached a milestone of 75 million combined operating hours. The current fleet of gas turbines totals more than 2,800 turbines across six continents. Main features includes reaching full power within 10 minutes, direct drive for 50-hertz and 60-herts power generation, variable speed for mechanical drive, dual-fuel capability for distillate or natural gas, reduced NOx with dry low emissions combustor and natural gas fuel and optional steam or water injection system for NOx control. The first LM2500 gas turbine began operating on a U.S. Navy cargo ship, GE said in a release. The turbine consists of a 16 or 17-stage axial flow compressor, annular combustor, two-stage, high-pressure, single rotor gas turbine and efficient six-stage power turbine.

DOE Picks 8 Projects to Receive Funding for Cutting Cost of CO2 Capture and Compression The U.S. Department of Energy’s (DOE) National Energy Technology Laboratory has selected eight projects to receive funding to construct small- and large-scale pilots for reducing the cost of carbon dioxide (CO2) capture and compression through DOE’s Carbon Capture Program. The Carbon Capture Program is developing technologies that will enable cost-effective implementation of carbon capture and storage (CCS) in the power generation sector and ensure that the U.S. will continue to have access to safe, reliable and affordable energy from fossil fuels. The program consists of two core research technology areas, post-combustion capture and pre-combustion capture, and also supports related CO2 compression efforts. Current research and development efforts are advancing technologies that could provide step-change reductions in both cost and energy penalty compared to currently available technologies.

MidAmerican Building Iowa Wind Farms for $900 Million MidAmerican Energy says it will build its next two wind farms in northwest Iowa. The company says there will be 134 generators at the Ida County site and 104 at the site in O’Brien County, providing a combined capacity of 552 megawatts. The estimated investment for the two projects is $900 million. A MidAmerican vice president, Mike Gehringer, says that by the end of the year, more of MidAmerican’s electricity will come from wind than from any other single source. MidAmerican spokeswoman Ruth Comer says that by the end of 2016, when both projects are completed, the Berkshire Hathaway-owned company will have more than 2,000 wind turbines across Iowa. www.power-eng.com

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GAS GENERATION

Renewable Energy â&#x20AC;&#x201C; Pushing Gas Turbine Components to Their Cycling Limit! BY THOMAS R. REID, TG ADVISERS, INC.

as turbine maintenance intervals are determined by hours, starts, or a combination of both. The latter is often referred to as equivalent operating hours (EOH). The increasing integration of renewable energy sources into generation portfolios has meant changes in dispatch, and many traditionally base-loaded assets are being forced to load follow and on-off cycle, as seen in many gas turbine and combined-cycle arrangements across the country. With such shifts in operational patterns comes a shift in the failure modes that manifest, as well as the inspection techniques required to effectively diagnose these respective modes. Given the competitive marketplace, it is valuable to understand applicable failure modes and inspection techniques to effectively balance the fine line between scrapping parts prematurely and running hardware beyond safe conditions.

CYCLING VS. BASE LOAD FAILURE MODES When a unit starts and stops, it is exposed to significant cyclic stresses in addition to large thermal transients in the high-temperature sections of the engine. This can lead to thermal mechanical fatigue or low-cycle fatigue cracking. After cracks begin, they continue to propagate with each new cycle. If not addressed in time, liberation of a rotating blade can lead to substantial forced outage time and repair costs. For cycling units, it is also common to sustain damage at interface or contact surfaces. Damage occurs from the repetitive relative movement between surfaces, or as a result of increased deflection of the rotor through critical speeds. Some examples 8

of these surfaces include rotor to blade root interfaces, tip contact faces on adjacent shrouded blades, and compressor or turbine blade tips. In addition, cycling has been shown to increase coating spallation rates for coated parts, thus leading to premature oxidation of the hardware. The impact of cycling is not limited to a single section of the gas turbine. TG Advisers has been involved in root cause failure analyses ultimately attributed to cycling in the compressor, combustion, and hot sections of gas turbines. It is also important to understand base load failure modes. Base loaded machines are mainly limited by failure modes that result from prolonged operation at elevated temperatures. These failure modes include creep, coating/surface oxidation damage, and embrittlement. Creep damage is very difficult to detect non-destructively. As a result, hot section rotating blades often have conservative life guidelines. This design philosophy is understandable given the scatter in material properties, difficulty of detecting creep, and severity of a blade failure. The risk for failure modes that require extended time at high temperatures, such as creep, is less in gas turbines that exhibit cycle dominated maintenance intervals.

CYCLING-TARGETED INSPECTIONS The key to effective inspections is understanding the applicable failure modes and how they manifest. This holds true for broad condition inspections such as in-situ borescope inspections, as well as for detailed inspections completed during major outages. Prior to overhaul, and as a routine maintenance practice, users should

complete borescope inspections at recommended intervals. Although not a precise indicator of part condition, signs of major damage such as large crack indications, excessive wear or oxidation, foreign object damage, tip rubbing, and missing coating should be explored. It is important to document damage that occurs over time in order to track the progression of known conditions. During major overhauls, users should conduct cycling-targeted, non-destructive testing (NDT), particularly on rotating hardware. Depending on material, there are multiple NDT techniques that can identify cracks. These include liquid penetrant, magnetic particle, and eddy current inspections. Users should complete pre- and post-repair inspections, especially if weld repair is required. In addition, they should inspect the integrity of the coating and determine if new coatings are required. Always review repair inspection reports for non-conformances so as to understand the condition of hardware prior to reuse.

ASSESSMENT FOR PART REUSE With inspection results in hand, it must then be determined if it is safe to continue to use hardware. Recall the difference in failure modes between base loaded and cycling machines and the fact that many parts are life limited by time at temperature failure modes. When coupled with the results of the cycling targeted failure mode inspections, knowledge of the accumulated operating hours of hardware enables educated decisions concerning part reuse. Given the cost of replacement hardware, significant monetary benefits can be realized using this strategy. www.power-eng.com

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VIEW ON RENEWABLES

WIND POWER: Made for American Needs

BY JACOB ANDERSEN, CEO ONSHORE AMERICAS, SIEMENS WIND POWER & RENEWABLES DIVISION

he Department of Energy’s Wind Vision report recently laid out a plan to double wind energy in the U.S. by 2020, double again to 20 percent by 2030, and expand to over one third of energy production by 2050. With policymakers in Washington focusing on reducing greenhouse gas emissions, wind power is a natural complement to fast-growing natural gas – a prime building block for lowering carbon emissions. The U.S. already leads the world in the amount of electricity that is produced by wind – with more than 181 million megawatt hours in 2014 – and the cost of wind energy has dropped by half over the past five years. As a share of the nation’s energy mix, wind has grown from under 1 percent to nearly 5 percent over the past eight years – competing with natural gas for the top spot of new power added to the system. Because it is a low-cost solution with zero emissions, it is clear that wind energy will play an important role in cost-effectively meeting the goals set forth by the Obama administration. In order to continue to reduce the cost of wind energy, ongoing technology enhancements are essential. Because of performance enhancements, onshore wind is nearly reaching grid parity. At Siemens, we are committed to continually enhancing our technology in order to grow the wind industry here in the U.S. Earlier this year, at the 2015 AWEA WINDPOWER Conference & Exhibition in Orlando, Siemens announced the latest addition to our G2 product platform. This new SWT2.3-120 wind turbine builds upon 10

the proven design principles of our G2 – sweeping a greater area to make the platform. Nearly 8,000 units have been most of the available wind resource. installed globally. At an average wind speed of 7.5 meWith wind power becoming an ters per second (nearly 17 miles per increasingly important part of the hour), the Siemens SWT-2.3-120 yields U.S. energy mix, this new turbine an increase of nearly 10 percent in anwas designed in America specifically nual energy production (AEP) comto meet the needs of the American pared to that of its pioneering predemarket. The SWTcessor under the same “As a share of the 2.3-120 offers proven conditions – helping technology tailored nation’s energy to deliver higher reto local requirements mix, wind has turns and a decrease and designed to in the Levelized Cost grown from under lower the levelized of Energy . 1 percent to nearly cost of energy. Production of this Building upon the 5 percent over the new wind turbine achievements of the will begin in 2017, past eight years.” SWT-2.3-108, the new and we are pleased SWT-2.3-120 features a high-perfor- that its production will support clean mance 120-meter rotor that enables en- energy jobs here in the U.S., where we hanced energy production, lower sound have close to 2,000 workers in our new power levels and improved operating unit and service businesses. temperature and altitude capabilities. The nacelles and hubs will be asAt our aerodynamic R&D center in sembled at our facility in Hutchinson, Boulder, Colorado, the new blade type Kansas, and the blades will be manuwas designed to optimize the perfor- factured at our blade factory in Ft. Madmance of next generation wind com- ison, Iowa. And our national network ponents – resulting in an aero-elastic of wind service technicians is ready to blade design that improves efficiency keep these turbines running optimally and reduces loads through intelligent throughout their lifecycle. use of the blade’s flexing capabilities. With more than 5,000 wind turbines This allows for the SWT-2.3-120’s larg- installed in the U.S., Siemens is leading er rotor size without a proportional in- the effort to ensure that wind power is crease in structural loading – decreas- an increasingly important part of the ing wear and tear on the turbine. nation’s energy mix. The new blade was designed with the At Siemens, we have more than 30 goal of increasing energy production years of global experience in onshore for sites with medium to low wind con- wind – and this new turbine is the latditions, which comprise a significant est example of our strong commitment part of the U.S. market. The 59-meter to the growth of wind energy in the blades extend the reach of the rotor United States. www.power-eng.com

ENERGY MATTERS

Kicking Ash and Taking Names BY APRIL ESCAMILLA, BURNS & MCDONNELL, AND ROBYNN ANDRACSEK, P.E., BURNS & MCDONNELL AND CONTRIBUTING EDITOR

he new rules on Coal Combustion Residuals (CCR) have a novel requirement aimed at making compliance efforts transparent: many records must be posted on the internet to allow easy public accessibility. Requiring a website is an interesting development and is an obvious next step in regulatory communication. On April 17, 2015, the Environmental Protection Agency (EPA) published the final version of the federal CCR rule on the storage and disposal of CCRs generated by electric utilities. The CCR rule is expected to affect more than 1,000 active CCR management units throughout the U.S, particularly the owners and operators of CCR landfills and surface impoundments. The new rule includes provisions addressing the potential for catastrophic failure of CCR containments, groundwater monitoring, operational requirements, recordkeeping and reporting, as well as closure procedures for inactive or failing facilities. Under the rule, there are numerous requirements that must be performed by a professional engineer, and others by a qualified individual. The rule will require installation of groundwater monitoring wells, and a groundwater monitoring program for taking samples and assessing that data. In addition to thorough recordkeeping and notification requirements, owners and operators of CCR sites are now required to maintain a public website hosting all compliance information, including monitoring reports. The rule also outlines timeframes and procedures for site closure, and also details closure consequences for sites failing to meet www.power-eng.com

these criteria. The first provisions of this rule are expected to take effect on October 19, 2015. As part of these provisions, all owners and operators of over 1,000 identified active landfills and surface impoundments, currently receiving CCRs are now required to establish and maintain a website of CCR facility operational compliance data called “CCR Rule Compliance Data and Information.” The website must be made publically available, and host items identified in the CCR rule are required to be publically accessible. Some of the items that must be included are annual groundwater monitoring results, corrective action reports, fugitive dust control plans, structural stability assessments, emergency action plans, and closure completion notifications. As information is uploaded to the site, notifications must be sent to the state and local tribal authorities. The requirement for a website stems from another unusual aspect of the CCR rule: the rule does not require permits, does not require states to adopt or implement these requirements, and EPA cannot enforce these requirements. EPA has promulgated a rule that relieves itself of the burden of assessing compliance. Commenters on the draft rule fell on both sides of the argument as to whether or not civilian enforcement would be effective. Some were encouraged by the opportunity to enforce the rule themselves since “…citizens have shown no reluctance to challenge companies that they believe are not responsibly following environmental regulations.” Others felt “environmental justice

Robynn Andracsek

April Escamilla

communities were the least likely to mount a serious challenge to the industry because low income people are often less well-educated, have less access to computers and internet technology, are less knowledgeable of how to access and interpret environmental data, and are the least likely to have the resources for a time consuming legal battle.” The Freedom of Information Act (FOIA), enacted in 1967, is the usual method to obtain records about a plant’s operation: emissions, limits, or almost anything needed to demonstrate compliance (other than business confidential information). For larger, more publically sensitive projects such as those at power plants, many states have already adopted a policy of creating websites where the most requested documents can be downloaded by the public. This simple action saves the agency manpower in fulfilling repetitive FOIA requests. However, FOIA requests and state websites put the burden of transparency on the government and not the regulated entity. By requiring each coal plant to post their compliance information on the internet, neighbors, activists, and other interested parties can play armchair watchdog. For now, EPA seems to have met the needs of all parties involved. Citizens can scrutinize their local utility, state agencies can redirect their budgets to enforcing other regulations, and EPA can stay neutral until they are dragged into action by a lawsuit. And the utilities? While they are busy managing ash and protecting the environment, citizen groups will be watching every move. 11

RENEWABLE POWER

Large-Scale Solar on the Rise

BY ROBERT SPRINGER

he utility-scale solar energy industry is feeling its oats. The cost of generating electricity from solar power has plummeted in recent years, and experts say it will continue to drop. Utility-scale solar is on par with, if not cheaper than, power produced with fossil fuel in many markets in the U.S., and there are more than 27 GW of solar projects either under construction or in the planning stages. Yet, there are a few clouds darkening the utility-scale solar market. The darkest being the possible sun setting of federal investment tax credits (ITC) at the end of 2016. Solar has about 1 percent of the power generation market in the U.S., but the industry is scoring some historic firsts. Georgetown, Texas, about 50 miles north of Austin, recently announced that it will use solar and wind power to become one of a handful of U.S. cities running on 100 percent renewable energy. The solar power will come from a 150 MW project in West Texas, according to John Lamontagne, senior director of corporate communications at SunEdison. What’s interesting about the announcement is why the city chose SunEdison: price. “They did it because we were the lowest cost option for local ratepayers,” Lamontagne says. “In other words, 12

solar energy (along with wind power) were the cheapest ways to power that town.”

PROJECT PROFILE There are two main ways to generate solar power: photovoltaic cells or concentrated solar power (CSP). CSP uses mirrors to focus solar energy to create heat, which can then power a traditional steam turbine. Photovoltaic cells use an electronic process to convert sunlight into electricity. The Ivanpah Solar Electric Generating System uses solar thermal technology to produce energy. Unlike traditional solar farms, more than 300,000 computer-controlled mirrors track the sun and reflect it towards boilers that sit atop immense towers. Steam is created when the concentrated light hits the boilers. The steam is piped to a turbine where it creates electricity. Ivanpah, which has been live since January 1, 2014, has three units with a total generating capacity of 377 MW. Units 1 and 3 provide power for Pacific Gas & Electric while unit 2 sends electricity to Southern California Edison. The plant has a 30-year license to operate on public land in California’s Mojave Desert, 45 minutes southwest of Las Vegas. About 65 full-time operations and maintenance employees work at the plant. Ivanpah, a partnership between BrightSource Energy, Google and

NRG called Solar Partners, was built by Bechtel. NRG Energy Services handles the plant’s operations and maintenance. The plant reaches full load during sunny days, says Mitchell Samuelian, vice president of operations and maintenance for NRG Renew and the former general manager of Ivanpah. “On sunny days we’ve made over 103 percent of our estimated energy that we were supposed to reach in the year,” he says. www.power-eng.com

Author Robert Springer is an Oregon-based freelance journalist covering the energy industry. His work has been published in several publications, including RenewableEnergyWorld.com and Power Engineering magazine.

The Ivanpah Solar Electric Generating System uses mirrors to direct concentrated solar power at a boiler, which produces steam to power a turbine and produce clean electricity for Northern and Southern California. Photo Courtesy: Ivanpah Solar Electric Generating System

The challenge is how to produce the most electricity during partly cloudy weather. The goal, explains David Knox, senior director, wholesale and new business communications at NRG, is to “collect as much solar energy as you can to start it up as quickly as you can, and then to continue that throughout the day, whether it be high noon or early evening and optimizing that throughout the entire day.” This is technically very challenging www.power-eng.com

to do, according to Samuelian, “Because you’ve got clouds moving in and out and you’ve got a steam plant with thermal inertia and the parts and pieces move around,” he says. In the early morning, virtually all of the mirrors are aimed at the tower, but as the day goes on some go into a standby position so the tower doesn’t overheat. The process is regulated by infrared cameras, Samuelian says. “They monitor the boilers surface with

infrared cameras, and they balance turbine load with the amount of solar they’re putting in and with how much sunlight’s in the sky,” he says. The boiler has three sections – super heat, reheat and evaporator – and multiple mirrors heat a different section of the boiler. Supercomputers balance the energy on the three spots and give aiming signals to each unit every 10 seconds, according to Samuelian. “I think that people don’t understand 13

RENEWABLE POWER

the complexity associated with that. I mean these are actually run by big supercomputers that control the system,” says Samuelian. The plant uses recycled water, and is using much less than originally thought, at about 40 percent of the 100 acre feet allotment for all three units, according to Samuelian. Using air-cooled condensers helps, as does having “a closed loop cooling system that ejects the heat to the air rather than evaporating water. There’s a golf course next to us out in the desert, and I think we use the amount of water equal to two holes on the golf course,” Samuelian says. Another challenge is the sheer size of the plant. A coal-fired plant of similar size would have a much smaller footprint, Samuelian says. Ivanpah’s three units cover about 3,000 acres and is about five miles end to end. “So if I’ve got someone working in the solar field on one end of the plant and I need them to go look at something else on the other end of the plant, there’s restrictions on what speed you can drive onsite, for wildlife considerations, and creating dust, and so, the speed limits like 10 miles an hour,” says Samuelian. It takes about half an hour to go from one end of the plant to the other.

FOLLOWING THE PHOTONS: SOLAR IS MORE THAN PANELS Solar panels get the lion’s share of the publicity, but they’d just be large, shiny mirrors without the ability to take the electricity the solar panels produce from the panel to the grid. ABB, a global provider of power and automation technologies, manufactures and installs the equipment that allows utilities to get solar energy onto the grid. ABB’s products take over once the solar panels have converted the energy from photons into DC power, says Bob Stojanovic, ABB’s director of solar power for North America. “What ABB 14

makes is everything from the connectors that connect the cabling to the devices,” he says. Groups of solar panels (or “strings”) run in a series and in parallel until they get the maximum voltage they’re designed for, and the electricity is taken

step-up transformer” or padmount transformer, he says. The transformer typically boosts the voltage up to 34.5 KV. Although there are small losses during the conversion process, the final boost to 34.5 KV will decrease the loss as the power is sent to the substa-

ABB provides concentrated solar power and thermal automation solutions for solar farms around the world, including this customized application with eSolar’s Sierra SunTower facility in Southern California. Photo Courtesy: ABB

to a combiner box, which is a group of fuses and switches that take the input from the strings and combine it into a single output, according to Stojanovic. “And that typically runs back to another larger combiner box, which is typically a bunch of breakers or large fuses that take the rest of these strings and combine it into one big DC input into an inverter,” he says. The DC power needs to be converted to AC to reduce losses and because that’s what the North American grid supports. Stojanovic says they typically get somewhere around 300 to 690 volts of AC out of the inverter, and “then it goes through what’s called an inverter

tion, according to Stojanovic. “Inside the substation you’ll typically string, depending on the plant design, somewhere between, five to eight converters together on the same circuit, and you’ll bring it back to a main breaker, a feeder breaker which will then feed it into the main power transformer,” he says. ABB manufactures turnkey substations and almost all of the equipment that’s in the substations, Stojanovic says, “Everything from the reclosers to the tank breakers to the power transformers, the current transformers, and the instrument transformers where you measure power and voltage.” Stojanovic says that ABB has no www.power-eng.com

desire to enter the solar panel market, although the company looked into it a few years ago, as they realized it was not a core competency. “What we manufacture is power and automation equipment. That’s really where we can add value,” he says.

WHAT HAPPENS IN 2017? There are a myriad of predictions for what would happen to the U.S. solar industry if the federal investment tax credit were to decrease from the current 30 percent to 10 percent in 2017. The predictions range from an extreme disruption of the industry to a 12 to 18 month hiccup in the industry’s rapid growth of the past few years. “I think right now people are proceeding with cautious optimism,” says Katherine Gensler, director of government affairs for the Solar Energy

Industries Association (SEIA). “This is in contrast to say the last five or six years, where there was sort of a booming industry and a growing industry.” Gensler adds that the eight year ITC extension that the industry received in 2008 allowed the industry to grow and especially helped larger utility-scale projects that had long lead times. Charles Pimentel, Solar Frontier’s chief operating officer, is not optimistic that congress will extend the ITC in its current form, although he is “confident that congress will provide some kind of interim solution, whether it be a complete extension, or whether it be some kind of safe harbor, or some kind of grandfathering in of projects completed by the end of 2016,” he says. He doesn’t foresee long term damage to the industry if the ITC is allowed to expire. “Will the industry cease to

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exist? No, definitely not. It has become very competitive to the point where I think it would certainly cause a considerable slowdown in the industry, but I’m confident that the industry can absorb it if it’s forced to,” he says. “It will certainly spur a high level of consolidation in the industry and only the very strong and very efficient will survive the expiration of the ITC. “ David Feldman, senior financial analyst at the National Renewable Energy Laboratory, notes that the personal homeowner credit completely goes away, so the distributed market could be harder hit than the utility-scale one. He also thinks it’s time for the ITC to go away entirely, albeit gradually. “The best thing that I think that could happen is that they just agree to somehow put some sort of orderly ramp-down in place rather than just a hard cliff; but I

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RENEWABLE POWER

Solar Frontier’s CIGS solar modules provide 82.5 MW of the Catalina Solar Project’s 143 MW. The project is near Bakersfield, California. Photo Courtesy: Solar Frontier

think whoever’s in office, it’s going to take congress as well as the president to decide what the policy is going forward. But all energy is policy, so it’s not just solar,” he says.

NET METERING: A DEBATE IN MANY STATES Net metering, or the process of selling excess electricity generated on-site back to a utility at retail power rates, is an issue that utilities and solar-using rate payers are passionate about. The rate at which customers are paid for energy sold back to a utility impacts its bottom line and the cost effectiveness of a rooftop solar installation, experts say. Pimentel says that while net metering does impact a utilities bottom line, it won’t destroy their business model as rooftop solar is such a tiny percentage of the energy generated in North 16

America. “If a homeowner is typically paying the utility $250 every month and all of a sudden the utility is only getting $15 a month, that impacts their revenue,” he says. However, if a utility has 2 million customers and only 5,000 use solar “it’s not going to destroy the utility. It will affect their revenue and their economics, but it’s certainly not going to destroy them,” he says. It makes sense for customers to be paid the retail rate, according to Feldman, as utilities don’t have to pay for pay transmission charges, the facilities are collocated and there are other benefits which make distributed solar worth a higher value price. The solar industry itself is of two minds about net metering. In California, the SEIA and the Alliance for Solar Choice have asked the public utilities

commission to leave things as they are, while Pacific Gas & Electric and Southern California Edison want payments lowered to new net metered installations.

FUTURE OF SOLAR IN N.A. While experts agree that solar has a place at or near the head of the table of renewable energy options for North America, the industry has some substantive challenges in addition to the possible expiration of the ITC at the end of 2016. ABB’s Stojanovic is an “optimist” when it comes to technological innovations that will continue to drive down equipment costs and increase efficiencies in the next few years. “They’ve basically proven everybody wrong over the last five years by blowing away whatever cost curves they thought they www.power-eng.com

had in line,” he says. Solar’s biggest challenge going forward is making energy that’s affordable in the daytime also affordable at night, Stojanovic said. “I don’t think cost for solar is the issue anymore,” he says. Interconnection continues to be an issue, according to Feldman. Putting the right amount of solar technology in the right location at the right cost is a challenge. He says that a utility industry that has placed a high premium on reliability (a good thing) might be acting too conservatively when it comes to solar. In addition to reliability, flexibility and storage are important factors for utilities to consider, Feldman says. Samuelian thinks era of the mega-solar projects is over, as the low price of oil and natural gas is “really kind of driving the energy market in general,” he says. Knox sees the home solar market as “an incredible growth market,” he says. “We just really see a huge potential for the home solar market, not instead of but in addition to the utility-scale market.” Many different technologies – including wind, storage, diesel generators and solar – could converge to help create a self-sustaining micro grid, Samuelian says. The number of states that have aggressive solar and renewables programs has grown exponentially, Pimentel says, with North Carolina being the poster child for this group. “Two years ago, nothing was going on in North Carolina, and now North Carolina will do gigawatts next year,” he says. Georgia is also getting into solar in a big way, according to Pimentel. New markets will be important for the industry, Feldman says, as states start to satisfy their Renewable Portfolio Standards (RPS). If Arizona, for example, hits its RPS, utility-scale solar might not make sense there as the demand will have evaporated. On the other hand, states like California www.power-eng.com

and Hawaii have very aggressive RPS’, which could balance out the demand. Solar is also competing against wind, Feldman notes. Gensler says that there is “still some trajectory” left in the market through 2016, but large utility-scale solar

plants are not being planned for post 2016 until the ITC debate is resolved. “There’s a lot more uncertainty about the near-term future, but then once we get through the uncertainty, the industry is strong and will continue to grow,” she says.

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Author Matthew Fischer is Product Leader, Dry FGD Systems, and Greg Darling is Product Leader, CFBS Systems, for Amec Foster Wheeler North America Corporation Global Power Group â&#x20AC;&#x201C; Environmental Systems.

EMISSIONS CONTROL

JEAâ&#x20AC;&#x2122;s Northside Generating Station includes two Amec Foster Wheeler CFB boilers, each producing 831,000 ACFM of flue gas. Each boiler uses a single SDA followed by a pulse jet fabric filter to treat the flue gas produced by the pet coke- and coal-fired unit. SO2 emissions are reduced up to 90 percent and SO3, HCl, and HF emissions are reduced up to 99 percent. The plant has been in operation since 2002. Photo Courtesy: Amec Foster Wheeler

Circulating Fluidized Bed Scrubber vs. Spray Dryer Absorber

BY MATTHEW FISCHER AND GREG DARLING

any utilities are under pressure to add flue gas desulfurization to their coal-fired units in response to more stringent air emissions regulations. There are a number of multi-pollutant compliance options available that have an edge over wet flue gas desulfurization systems. This article 18

sorts out the difference between stateof-the-art circulating fluidized bed scrubbers and the latest advanced spray dryer absorber designs. By Matthew Fischer and Greg Darling, Amec Foster Wheeler The converging U.S. Environmental Protection Agency (EPA) rules for reducing mercury, metals, acid gases, and organic compounds (Mercury and Air

Toxics Standards or MATS), Regional Haze (RH), and SO2, NOx, and particulates (Cross-State Air Pollution Rule or CSAPR) have ratcheted up the pressure on coal-fired generators to quickly reduce a variety of pollutants. The EPA estimates that CSAPR alone requires more than 3,000 units at more than 1,000 plants located in 28 states to reduce emissions that cross state lines and contribute to ground-level ozone and fine particle pollution. CSPAR Phase 1 compliance takes effect this year while MATS and RH reduction are ongoing programs. The debate over what limits will be imposed has now shifted to how individual units will comply with the prescribed deadlines. There are as many technical approaches to meeting new emission limits as there are differences in plant designs. Adding to the complexity of any solution is the uncertainty of future rules that will require further reductions of an expanding range of pollutants. In the past, SO2 capture on a large scale was the province of wet flue gas desulfurization (WFGD) technology. It has the advantage of a relatively low operating cost and uses readily available limestone as the reagent, which can be recycled into a number of useful products to offset operating costs. However, WFGD scrubbers do have disadvantages, such as large capital and high maintenance costs. By design, many WFGD systems require periodic discharge of the scrubber liquor to maintain solids www.power-eng.com

SDA Design Details

TECHNOLOGY COMPARISON

absorber (SDA), which sprays atomized lime slurry droplets into the flue gas. Acid gases are absorbed by the atomized slurry droplets while simultaneously evaporating into a solid particulate. The flue gas and solid particulate are then directed to a fabric filter where the solid materials are collected from the flue gas. Amec Foster Wheeler has installed 60 SDA units representing over 4,500 MW of plant capacity. The second is the circulating fluidized bed scrubber (CFBS, which circulates boiler ash and lime between a scrubber and fabric filter. Amec Foster Wheeler has install 78 CFB scrubber units representing over 7,000 MW of capacity in the power and industrial industries. Spray dryer absorber SDA technology operates using absorption as the predominant collection mechanism. In general, the acid gas dissolves into the alkaline slurry droplets and then reacts with the alkaline material to form a filterable solid. Intimate contact between the alkaline sorbent (hydrated lime) and flue gases make the gas removal process effective.

Interest in dry or semidry FGD scrubbers is increasing due to its ability to capture mercury, acid Perforated Distribution gases, dioxins, and fuPlate & Flow rans, in addition to SO2 Flue Gas In Straightener and particulates. These multi-pollutant technolTwo Fluid Two-Phase Nozzles ogies also have added Reaction Reaction Vessel benefits: no liquid disProcess charge and significantly reduced water consumption, which is increasFlue Gas Out ingly important to power plants that are under Solids Discharge Hopper pressure to reduce water consumption. Two multi-pollutant technologies dominate The SDA uses hydrated lime to treat flue gas. The heat of the flue gas evaporates the droplets, which cools the flue gas. Cooled flue gas with the utility sector. The the dried products is directed to a fabric filter. fundamental difference Source: Amec Foster Wheeler between the two techand/or chlorides. This effluent requires nologies is the manner in which the readditional treatment which adds capital agent is mixed with the incoming flue and operating costs. Also the uncertain- gas to remove the desired pollutants. ty of future regulations, specifically the The first technology is the spray dryer Steam Electric Power Generating Efflu2 Two-Fluid Nozzles Released ent Limitation Guidelines (ELG), may require additional discharge treatment. Lime Slurry WFGD is also limited in its ability to capture mercury and SO3. Some plants Atomizing Air Nozzle have reported increased mercury reAtomizing Air Air Shroud Reservoir Lime Slurry moval as a desirable, but expensive Shroud Air co-benefit when a selective catalytic reduction (SCR) system for NOx removal was installed upstream of the WFGD scrubber. Other plants have also addLance Assembly ed injection of one or more proprietary reagents into the furnace, such as dry sorbent injection (DSI), as a means to increase the mercury removal co-benefit. Stacking technologies is not a cost effective long-term strategy to reduce Two Fluid pollutantsâ&#x20AC;&#x201D;itâ&#x20AC;&#x2122;s unnecessarily expenNozzle Inserts sive and reduces the overall reliability of The optimized two-fluid nozzle design ensures balanced atomizing air distribution in order to produce a the entire unit. A more holistic solution consistent droplet size, and reduced compressed air consumption by a quarter. Also, tungsten carbide inserts have significantly reduced nozzle wear. is preferred. Source: Amec Foster Wheeler

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EMISSIONS CONTROL

CFBS Design Details

3 Fabric Filter

CFB Scrubber

Water Hydrated Lime Air Air Solid ByProduct

Inlet Flue Gas and Ash

frequency (1–3 weeks continuous operation), reduced cost of operation (20-25 percent less compressed air consumption), and longer life with its new tungsten carbide inserts. In addition no special tools are required for routine maintenance. The SDA design also provides additional operating flexibility for the entire plant. For example, any two-fluid nozzle can be removed for maintenance without decreasing boiler load. Emissions performance is maintained even when multiple twofluid nozzles are taken out of service. The SDA is also capable of high unit turndown, down to 25 percent of rated flue gas flow without recirculation of the flue gases while maintaining emission requirements. The design of the unit also provides for fast load response enabling unit cycling or load following. An added advantage is low absorber pressure drop that keeps the parasitic fan power loss to a minimum.

Reactor Ash Drain The principal operating steps is recycling a solids/hydrated lime and water mixture in the flue gas flow to capture pollutants, cool the gas, and then capture solids in a fabric filter. Other reactive absorbents like activated carbon can be added to target specific pollutants. Source: FWEC

The key to efficient performance is the means used to atomize the lime slurry into droplets within the gas stream. The SDA offered by Amec Foster Wheeler utilizes a two-fluid nozzle to atomize the lime slurry. The fine spray provides increased contact area in order for gas absorption to occur compared to the CFBS (it’s easier to mix a gas with a liquid than with a solid). Acid gases are then absorbed onto the atomized droplets. Evaporation of the slurry water in the droplets occurs simultaneously with acid gas absorption. The cooled flue gas carries the dried reaction product downstream to the fabric filter. This dried reaction product can be recycled 20

to optimize lime use. Industry experience with earlier SDAs was they were expensive to operate and maintain regardless of the atomization mechanism used. Amec Foster Wheeler has redesigned its two-fluid nozzle to improve the distribution and mixing of atomizing air with lime slurry, which improves mixing efficiency and decreases operating and maintenance costs. The optimized nozzle design delivers even atomizing air distribution to produce a consistent droplet size while providing longer nozzle life. In 14 field applications, the optimized nozzle has demonstrated low cleaning

The 420MW-rated coal-fired unit at Basin Electric’s Dry Fork Station has operated the world’s largest CFBS since it entered service in June 2011. Since it began operation, the CFBS has exceeded its design performance reducing SO2 by 95 percent to 98 percent. Photo Courtesy: Basin Electric Co-Op and Wyoming Municipal Power Agency

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Circulating fluidized bed scrubber Boiler flue gas enters the CFBS (with or without ash) at the bottom of the up-flow vessel, flowing upward through a venturi section that accelerates the gas flow rate, causing turbulent flow. The turbulator wall surface of the vessel causes highly turbulent mixing of the flue gas, solids, and water for 4 to 6 seconds to achieve a high capture efficiency of the vapor phase acid gases and metals contained within the flue gas. The gas and solids mixture then leaves the top of the scrubber and the fabric filter removes the solid material. Recycled solids/hydrated lime and water mix with the turbulent flowing gas moving vertically through the vessel, which provides gas cooling, reactivation of recycled ash, and capture of pollutants. The CFBS process achieves a very high solids-to-gas ratio, which dramatically improves the ability of vapor phase pollutants to find adsorption sites on the colliding solid particles. The water plays the important role of cooling the gas to enhance the adsorption of the vapor phase pollutants onto the solid particles. The gas and solids mixture exit at the top of the scrubber and enter the fabric filter where solids entrained in the flue gas are captured and recycled back

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EMISSIONS CONTROL

to the scrubber to capture additional pollutants. A portion of the recycled solids is removed from the fabric filter in order to maintain the right quantity of material in the circulating loop. The effectiveness of the sorbent is largely a function of residence time. A CFBS can keep solids in the system from 20 to 30 minutes. This is a sufficient period of time for the sorbent to react with the acid gases. Two independent control systems maintain the dry flue gas at optimum temperature and at adequate removal efficiency by controlling the amount of water added and the amount of fresh sorbent added separately. As a result, unlike the SDA scrubber, pollutant capture is not limited by inlet

flue gas temperature.

TECHNICAL COMPARISON Table 1 summarizes the important technical differences between the SDA and CFBS options. Table 2 summarizes the performance differences. In general, the CFBS is slightly better at SO2 control, with up to 98+% capture with high amounts of sulfur in the fuel. Plant turndown capability is equivalent, when the CFBS is equipped with flue gas recirculation. In general, the CFBS offers slightly greater SO2 removal flexibility when compared to SDA. The amount of fresh lime injection is not limited by flue gas temperature thus allowing greater SO2

Turbulent Mixing

Dry Flue Gas with Solids

Multiple Venturi Design

CFB Scrubber

Water

Hydrated Lime

Raw Flue Gas & Ash

Recycled Solids

Absorber Bottom

Flue gas enters vertically upward into the scrubber and through a set of venturis that accelerate the gas flow. Wall turbulators increase flue gas and reagent mixing efficiency. Multiple venturis allow a single scrubber to be scaled up to 600 MW in unit capacity. Source: FWEC

scrubbing performance over a wider range of fuel sulfur content. SDA systems are temperature limited because fresh lime is introduced as slurry (lime and water). In addition, due to water being introduced independently and purely for temperature control, the CFBS can utilize lower quality water, as it is not used for pebble lime hydration. The CFBS has the ability to effectively treat more flue gas volume than an SDA. The multiple venturis present allow a single CFBS vessel to be scaled up to almost twice that of the SDA vessel option. Turndown capability is built into the SDA design, where a CFBS requires a flue gas recirculation system in order to achieve equivalent turndown. An SDA utilizing the two-fluid nozzle design can maintain required emission levels down to approximately 25 percent of MCR. In a CFBS at lower loads additional recirculated flue gas is required to maintain bed velocities in order to maintain required emission levels. If turndown during non-peak power demands is a consideration the additional parasitic load is an operating cost consideration for the CFBS. The CFBS provides greater sorbent utilization compared to a oncethrough SDA system as reagent recycle is incorporated into the design. However, due to the difference in hydration efficiency, a SDA equipped with recycle offers greater overall sorbent utilization compared to CFBS. In an SDA the recycled solids are slurried within a tank providing essentially 100 percent hydration. In a CFBS water spray nozzles wet the dry recirculated solids as it passes through the vessel. This hydration process is less efficient due to the quantity of recycled solids and the lack of sufficient wetting time. All the other performance characteristics are relatively equivalent including net auxiliary power. The pressure drop in the SDA (10 inches H2O) is much www.power-eng.com

Key Technical Characteristics of SDA and CFBS Performance characteristic

SDA

CFBS

< 2.5%

< 3.5%

95 – 97 %

95 – 98+ %

40,000 – 1,000,000 acfm

75,000 – 1,800,000 acfm

25% without FGR

50% without FGR

Calcium hydroxide slurry

25% with FGR

Sorbent Treatment

Slaker

Dry calcium hydroxide

Sorbent Utilization (Molar Ca/S ratio)

1.4 – 1.5 (without recycle)

1.3 – 1.4

Fuel sulfur content SO2 removal % Capacity per vessel Turndown capability, % of MCR flue gas flow Sorbent

1.15 – 1.25 (with recycle) Temperature limited

Temperature independent

Water quality

Medium

Low

Capital cost

Slightly lower

Slightly higher

Large in power island, small overall

Moderate in power island, small overall

Control flexibility

Footprint, includes fabric filter

NO ONE SIZE FITS ALL TECHNOLOGY

Notes: MCR = maximum continuous rating; FGR = flue gas recirculation; acfm = actual cubic feet per minute Source: Amec Foster Wheeler

Key Performance Characteristics of SDA and CFBS

Parameter

SDA

SO2 removal efficiency, %

Expected SO2 removal, %

98+

SO3 removal, %

95+

HCl/HF removal, %

Total PM Removal efficiency, %

99+

Mercury removal efficiency, % (with or without PAC)

Equal

Auxiliary power consumption

Higher

Lower

Total power consumption (including ID fan)

Equal

Water consumption

Equal

Noise

Equal

Pressure drop, inches H2O

Availability, %

CFBS

Notes: ID = induced draft; PAC = powdered activated carbon; PM = particulate matter Source: Amec Foster Wheeler

less than the equivalent sized CFBS (16 inches H2O), which is proportional to ID fan power consumed. However, the auxiliary power used by the SDA, www.power-eng.com

approximately equivalent. However, depending on the unit capacity, pressure drop may have a greater operating cost impact compared to the additional auxiliary power of an SDA. Both technologies are simple, reliable, and robust. When maintenance of the CFBS is required, the accumulated solids can easily be removed through the bottom of the scrubber. Also, the water nozzles are low maintenance and can be replaced with the unit in operation. SDA two-fluid nozzles may also be removed and maintained during plant operation without loss of unit capacity.

principally for compressed (atomizing) air, exceeds that required by the CFBS. The net result is that the total auxiliary power used by the either option is

In the past, dry scrubbing technology was typically chosen over WFGD technology for its much lower capital cost and water usage, provided that the boiler size was not too large and the fuel sulfur content was not too high. Today, CFBS technology has broken through these limitations with single unit designs up to 600 MW backed by operating units coal-fired units of over 500 MW and on fuels with sulfur levels above 4 percent by weight. SDA have also been deployed on equal-sized units but are less tolerant to fuel sulfur content change. The utility retrofit market has leaned more toward the CFBS technology of late due to the higher SO2 removal performance. The limited turndown without flue gas recirculation and use of hydrated lime is also viewed as a disadvantage. However, the new generation of SDA nozzles now available has significantly reduced cleaning frequency, which was a major criticism by early adopters. With extended nozzle life and reduced compressed air consumption, the performance gap between the SDA and CFBS has narrowed. Specific site and environmental permit requirements will be the determining factor. 23

SMALL GAS TURBINES

A 6 MWe ORC installation with air-coled condenser in Germany. Photo courtesy: Siemens

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Improving the Flexibility and Efficiency of Gas Turbine-Based Distributed Power Plants

BY MICHAEL WELCH AND ANDREW PYM

or the past 100 years across most of the world, consumers have received their electricity from large central power plants, which provide energy to the entire system from a single location via a network of transmission lines. This model, which relies heavily on fossil fuels, is facing an increasing number of challenges. The major initial efforts to reduce the environmental impact of power generation centered on fuel switching from coal to natural gas, with plans for massive centralized coal-fired power stations giving way to more efficient, less polluting, natural gas-fired power plants in the so-called â&#x20AC;&#x153;dash for gas,â&#x20AC;? changing the power mix from predominantly thermal coal-fired steam turbine plant to a more even split between coal and combined cycle gas turbines. With increasing global efforts to reduce greenhouse gas emissions, there is an increasing penetration of intermittent and variable renewable energy.

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Both wind and solar generation output vary significantly over the course of hours to days, sometimes in a predictable fashion, but often imperfectly forecast. This intermittency and variability of wind and solar power generation presents challenges for grid operators to maintain stable and reliable grid operation, especially in countries where renewable power is given dispatch priority, requiring redundancy and flexibility in fossil-fueled power generation so that the system can respond quickly to these fluctuations, outages and grid support obligations. Predominantly to date this has been achieved by operating central power plant so that they maintain their connection to the grid but run at part-load so that they can rapidly respond to transients on the system network. Without sufficient system flexibility, system operators may need to curtail power generation from wind and solar sources. The centralized power generation model has created a trend over the past century towards ever

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Renewables Impact on Available Power Generation Over a Week In Germany In 2013

Pumped Storage Solar

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FLEXIBILITY OF A MULTIPLE GAS TURBINE SOLUTION

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increasing unit sizes, based on the assumption that larger units and bigger plant provided lower cost power generation due to economies of scale, with small increases in power generation efficiency also contributing to this. The accepted penalty was losses in the transmission and distribution networks, and the potential for consumers to lose their power supply in case of transmission or distribution system outages. However, maximum efficiency occurs at full-load, so operating a large central plant at part-load reduces the efficiency of power generation considerably, and the need for part-load operation may impact on the operational range of the power station due to the need to comply with emissions legislation. In addition, cycling of the units, ramping up and down in load, can create the need for more frequent maintenance and power station outages. A large utility-scale turbine undergoing major maintenance can require around two to three weeks outage for disassembly, inspection, parts replacement and reassembly. Cycling also reduces part life and severely impacts plant 26

the ability to operate at low output levels, while still maintaining high efficiencies, low emissions and low power plant maintenance downtimes. Distributed Generation is also enabler for enhanced smart grid capabilities.

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economic returns and in some cases, overall viability. Another issue facing centralized power generation is water usage. In many parts of the world, water is a scarce resource for which power generation competes with agricultural, industrial and domestic needs. In 2010, World Bank estimates indicated 15 percent of the worldâ&#x20AC;&#x2122;s water withdrawals were used for energy production, and with electricity demand expected to grow 35 percent by 2035, water usage for power generation will increase significantly, especially in systems relying on the centralized generation model. Distributed Generation can help address all the above issues. By building smaller, more flexible power plants closer to the actual load centers, network operators can better compensate for the intermittency of renewables, reduce transmission system losses and improve security of supply and reduce capital expenditure on capacity expansion/augmentation while the power plant operators by using multiple units can optimize the plant design to meet the needs of the network operators with fast ramp up and turn down and

Conventional modern large-scale Combined Cycle Gas Turbine power plant (CCGT) are usually based on a single gas turbine with a single steam turbine (1+1 configuration), or two gas turbines with a common steam turbine (2+1 configuration). While this configuration offers very high efficiencies at full load, in excess of 60 percent today, the efficiency falls as load reduces. There is also a minimum emissions compliance load, which limits the operating range of the power plant. With around 1/3 of the total station power generated by the steam turbine, it can take over 30 minutes to achieve full station load. In addition, with the gas turbine shut down for maintenance in a 1+1 configuration, the complete station is offline, whereas in a 2+1 configuration, an outage of one gas turbine will reduce station power generation to less than 50 percent of its rated output. A solution based on multiple gas turbines may offer much greater flexibility, improved efficiency across the power range and enhanced operability compared to a conventional CCGT solution. The Advantages of Modularity Modularity can help enhance plant flexibility and reliability. By having multiple units, load can be shared across them, and units switched on and off to match the required load. This enables the power plant to operate efficiently over a much wider load range within the permitted emissions limits than a conventional CCGT can achieve. Future plant expansion is easy www.power-eng.com

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to achieve simply by adding one or more units whenever required, either at the same location or at a different tactical point in the power network, rather than having to build a new large power plant and associated transmission system. By distributing capacity in this way a ‘virtual generation’ benefit is also achieved via loss offset in the transmission network. The modular attributes also enable plant to be moved easily if market conditions change or the plant is sold. This reduces operational and financial risk which is beneficial for accessing finance at more favorable terms. Small gas turbines tend to come in pre-designed, pre-assembled standardized packages which have undergone significant levels of factory testing and require only a simple concrete foundation. This reduces the amount of planning, engineering, site installation and construction work required compared to a conventional power plant, enabling the power plant to be brought online faster, while still maintaining a competitive first cost, and reduces the risk of construction delays and associated contract penalties in addition to lost revenue. In addition, these packages can be supplied with weather-proof acoustic enclosures, eliminating the need for buildings. All the auxiliary systems required for turbine operation – including the www.power-eng.com

control system - can be mounted ei- second and 200 kW/second. ther within the enclosure, adjacent to However, gas turbines can also acthe enclosure or on the enclosure roof, cept step load applications while still minimizing the number of intercon- maintaining power generation withnections required. in the required frequency and voltage Having multiple units also helps limits. The maximum acceptable step maintain high power plant availabil- load depends on the gas turbine design ity and output. As mentioned earlier, – a single shaft gas turbine can accept with a single gas turbine installation, a larger single load application than a maintenance outage means that the a twin-shaft variant – but this ability entire power station has to be taken of- to step load enables the turbines to fline. A power plant of similar output reach full load much faster than by but based on, say, 5 smaller gas tur- employing a simple ramp rate for loadbines can still generate 80 percent of ing. Figure 4 shows the comparison of rated station output with one turbine time taken for a twin-shaft 12MW gas out of service, 60 percent with two turbine to reach full load using the turbines out etc. Decentralized power maximum permissible load steps for plant using this concept have been used this particular gas turbine model – full for many years 3 in the Oil & Gas Typical Start Times for Open industry for onCycle Gas Turbines shore fields and offshore platforms 100 Trent with no possibiliSGT-800 ty to connect to a 80 power grid, with many Oil & Gas 60 operators choosing the so-called 40 ‘N+1’ configuration so that there 20 is a spare unit to ensure 100 per0 cent power output 1 2 3 4 5 6 7 8 9 10 is available even Minutes with one gas turbine out of service. load can be achieved in half the time Ramp Rate by applying load in steps. The ability of a power plant to reSingle-shaft gas turbine designs spond rapidly to variable grid demands can accept greater step loads, varying is critical in today’s power environ- from 50 percent to 100 percent dement with a high percentage of inter- pending on the model, rating and site mittent renewable power generation. conditions. In the case of a 50MW sinMultiple small gas turbines allow the gle-shaft gas turbine, it is possible to full plant load to be achieved relatively load the unit from zero to full load in quickly from pushing the start button two steps within 30 seconds. as the units can ramp up in parallel. Reducing Maintenance Outages The ramp rates of small gas turWhen scheduled maintenance is rebines typically range between 100 kW/ quired and parts need to be replaced, Power Output (%)

Typical Modular Outdoor Gas Turbine Generator 2 Set Installation

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Expected Ramp Rate and Step Load Acceptance for a Twin-Shaft 12-MW Gas Turbine

reducing the maintenance requirements still further.

FUEL FLEXIBILITY 14

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the large utility scale gas turbines require considerable downtime as the unit has to be disassembled on site, parts changed and then the unit reassembled. The smaller gas turbines are generally of Light Industrial or Aeroderivative designs which, while many variants have the capability for onsite maintenance as well, are primarily designed for off-site maintenance employing gas generator and turbine module exchange programs. This reduces the turbine outage times for major inspections from several weeks per unit to between one day and five days depending on the gas turbine model and the type of maintenance intervention required. Meanwhile in a power plant based on multiple units, the remaining units are still available to generate power, enabling the power station to stay online generating revenue, with only a relatively small percentage of total plant output unavailable. Routine maintenance requirements during plant operation are also low, with no requirement for highly skilled maintenance personnel to be permanently based on site and low consumption of consumables such as 28

While Utility-scale gas turbines are designed primarily for operation on pipeline quality natural gas with a premium liquid fuel such as diesel as an alternative or back-up fuel, the majority of smaller gas turbine models are able to operate on a much wider range of gaseous and liquid fuels. Low emissions combustion systems have also been developed that will operate on non-standard gas fuels, including those with variable compositions. This is a potentially important feature for decentralized power plant as it enables the power plant to operate on a locally available fuel, which,

lubricating oil. The various gas turbine OEMs are all working A 7.7 MW Tri-Fuel Gas Turbine on further developments to Installed in a Cogeneration 5 improve system reliability and Plant in the U.S. remote monitoring systems to enable unmanned operation for prolonged periods of time. As has been well-documented elsewhere, the output of a gas turbine is dependent on ambient temperature: as ambient air temperature rises, a gas turbineâ&#x20AC;&#x2122;s power output reduces. Conversely this means that if you design a power plant to give a specific output at the maxi- as some of these are classified as waste mum ambient temperature foreseen, gases, may also be more economical on cooler days more power is available than utilizing pipeline quality natfor dispatch. If there are distribution or ural gas. Examples of such potential transmission system constraints that gas fuels are landfill gas, digester gas, limit the amount of power that can be high hydrogen content gases such as exported, then on cooler days, while refinery gas or syngas, ethane and prostill producing maximum station out- pane. It is potentially possible to use put, the gas turbines will operate at two completely different gas fuels and part-load. Most GT OEMs calculate switch between these fuels as necesthe time between overhaul (TBO) for sary, determined by fuel availability or the various different gas turbine mod- pricing. Most gas turbines are available in els based on an Equivalent Operating Hours (EOH) formula â&#x20AC;&#x201C; part-load dual fuel configuration, able to operoperation can help extend the TBO ate on either gas fuel or liquid fuel. The www.power-eng.com

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Smaller open environmentally friendly manner for cycle (simple cy- base load, load following and peakcle) gas turbines ing service. Figure 6 compares the net have been used plant efficiency of a single 50MW class 40 4 x 12.5-MW gas turbines for peaking ap- aero-derivative gas turbine in open plications for cycle with four open cycle 12.5 MW 30 many years be- class gas turbines with performance cause they can be data calculated for an ambient air tem20 started quickly perature of 40Â° C. While at high loads 50-MW gas turbine and ramped up the single unit is more efficient, once 10 and down rap- the power plant output drops below idly to meet the 50% of rated plant output, the multi0 grid demands. In ple unit solution has a higher efficien0 10 20 30 40 open cycle, a gas cy as units can be turned on and off Power Plant Output (MW) turbine is rela- to maximize efficiency. The multiple Efficiency versus load comparison for a 50-MW gas turbine (light blue line) and 4 x 12.5-MW gas turbines (dark blue line) in open cycle at 40oC tively inefficient unit solution also offers a wider power ambient temperature. with efficiencies plant operating range from a combusvarying from tion emissions perspective. Most gas turbines can operate on 100 percent around 28% for a small industrial gas turbine models guarantee nitrous oxgas fuel or 100 percent liquid fuel, with turbine to just over 40 percent for the ide (NOx) and carbon monoxide (CO) rapid automatic changeover between larger aero-derivative gas turbines. In from 50% of rated load to 100% of the fuels with no requirement to tem- peaking applications, this is perhaps rated load, as required by most global porarily reduce load to undertake the not so much of an issue as the price legislation, although some units offer fuel change. The liquid fuels that may of electricity is very high during the these guarantees down to 30% or 40% be considered are typically #2 diesel, periods of gas turbine operation, but load. Therefore a single unit solution at kerosene, LPG and naphtha, although with increasing demand for flexible low loads will start to exceed the perthere are gas turbine models available power generation across the whole mitted emissions. A multiple unit soluthat can utilize Light, Intermediate day, a power plant today needs to be tion though enables the power plant and Heavy Fuel Oils, Residual Oils, able to operate efficiently and in an to have a greater turn-down capability Bio-Oils and even Heavy Crude Oils. On some gas turbines it is possible to 7 Efficiencies simultaneously operate on both gas and liquid fuels â&#x20AC;&#x201C; commonly referred 50 to as bifueling or mixed fuel operation 45 - using one fuel type to compensate for shortage of another. 40 There are examples of tri-fuel gas 35 turbine installations, with units capa30 ble of operating on a gas fuel and two 25 different liquid fuels, or a liquid fuel 20 and two different gas fuels. Figure 5 is a 15 gas turbine installed in a cogeneration 10 plant at a university in the U.S. and 5 configured to operate on either pipeline quality natural gas or a processed 0 0 20 40 60 80 100 120 landfill gas, with diesel as a back-up Seconds fuel in case of loss of gas supplies, while Typical gas turbine nominal efficiencies (vertical axis) by power output (horizontal axis) still meeting strict emissions limits. with complex cycle designs indicated by circles. Improving Part-Load Efficiency and Emissions Performance

Power Output (%)

Efficiency vs. Load Comparison

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temperature heat recovery steam generators (HRSGs) and steam turbine systems required to achieve this efficiency level adds considerable cost. Lower cost solutions using low pressure steam systems can be employed, but this reduces the plant efficiency. In addition, for decentralized plant located close to load demand, the availability of water may be an issue, or the operation and maintenance level required by classical steam solution cannot be easily accommodated, so an 8 alternative techEfficiency Variations nology to generate electricity from 41 ORC the wasted energy 40 Steam Cycle in the gas turbine 39 exhaust needs to 38 be considered. 37 Organic Ran36 kine Cycle (ORC) 35 Technology 34 The Rankine Cy33 cle is a thermody32 namic cycle which 31 converts heat into 33 66 100 work. For power Comparison of variation of efficiency with load based on a 25-MW power plant using multiple small turbines and ORC or 42 bar, 400oC steam to generation, by apcreate a combined cycle plant. plying heat externally to a closed gas turbines on the market with recu- loop, the working fluid is heated till perators and intercooling to improve it becomes a vapor, expands across efficiency, the simplest, most effective a turbine to drive a generator and is and most proven way to improve effi- then cooled and condensed ready to ciency is to use a combined cycle con- commence the cycle again. Water is figuration with energy recovered from normally the working fluid used, and the exhaust of the gas turbine to gen- the water (steam)-based Rankine Cycle erate additional power. Water (steam) provides approximately 85 percent of is the obvious choice as a working flu- worldwide power generation. id to generate additional power via a A utility scale gas turbine tends to steam turbine, just as in a conventional have a high exhaust gas temperature, large-scale CCGT. However, smaller typically between 530°C gas turbines are not optimised for com(990°F) and 640°C (1180°F), as the bined cycle applications, having rela- designs are optimized for combined tively low exhaust mass flows and ex- cycle applications with multi-pressure haust gas temperatures, and although level multi-pass boilers producing high combined cycle efficiencies in excess pressure, superheated steam (up to 160 of 55 percent can be achieved, the bar and 600°C) for inlet to steam turcomplexity of the high pressure, high bines with reheat between different Net Plant Efficiency (%)

while still complying with applicable emissions legislation. In the example in Figure 6, and assuming 50 percent turndown limit, the power plant will still meet emissions requirements down to 12.5 percent of rated power plant output. However, for a truly flexible power plant, the efficiency of the gas turbines needs to be as high as possible as well as providing as wide an operating range for the power plant as possible. While there are complex cycle

pressure levels within the steam turbine. This is how a modern CCGT achieves the high full load efficiencies quoted, and produces electricity at competitive prices through economies of scale. Smaller gas turbines have lower exhaust gas temperatures, typically between 460°C (870°F) and 550°C (1025°F) as they are optimized for maximum open cycle efficiency. This reduces both the volume and temperature of high pressure superheated steam that can be produced, reducing cycle efficiency. It is also not cost-effective to use the same Waste Heat Recovery Unit and Steam Turbine technology as developed to go with a 300 MW gas turbine on a 10 MW gas turbine. Therefore if a power plant is to be based on multiple small units, efficiency must be sacrificed to ensure cost-effectiveness, so lower pressure non-reheat steam systems are used, often with much simpler Once Through Steam Generators (OTSGs) that respond much more rapidly to changes in steam demand. However, at low pressures, there is a large enthalpy drop experienced when water is the working fluid, and a degree of superheat is required to avoid the risk of condensation, and associated erosion, inside the steam turbine. By changing the working fluid, a low enthalpy drop can be achieved, the need for superheating eliminated, as condensation within the turbine can be avoided, and the same efficiency achieved at a lower working pressure. Improved efficiencies at part-load are also attainable using ORC turbogenerators compared to conventional steam turbines. Organic Rankine Cycles for small gas turbines tend to use a high molecular weight hydrocarbon (organic) fluid such as cyclopentane, or silicone oil, as the working fluid for the turbine. This www.power-eng.com

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turbines are not turbines has quite a considerable imoptimised for pact, as can be seen in Figure 12. combined cycle Firstly, it can be seen that the ORC applications, gen- system adds about 25% additional erally having low- power output for the multiple small er exhaust tem- units for no additional fuel input. Sec25 peratures than ondly, this additional power improves the utility scale the plant efficiency so that at full load 20 gas turbines, and the overall net plant efficiency is in so they have re- excess of 40%, even on a hot day. This 15 duced high pres- efficiency improvement makes a nomisure steam raising nal 50MW plant based on multiple gas 10 capabilities. How- turbines more efficient and more flexiever, the lower ble than a plant based on a single open 5 Direct – 2 GTs exhaust tempera- cycle gas turbine across the whole load Oil – 2 GTs tures at both full range, and with the ability to achieve 0 and part-load en- load turn-down to around 10 percent 10 30 50 able ORC technol- of rated station power output while Ambient Temperature (oC) ogy to be readily still maintaining an acceptable comemployed to im- bustion emissions profile. allows high efficiency, larger diameter prove overall plant efficiency while still Multiple gas turbines can be conturbines to be utilized, operating at enabling multiple units to be installed nected to a single ORC turbogenerator, lower speeds, typically 3000rpm, with to maintain the overall power station providing the maximum output rating low mechanical stress – unlike small flexibility and operability. This config- of the ORC turbogenerator is not exsteam turbines which operate at speeds uration also has the additional advan- ceeded. This helps reduce the cost/kW up to around 10000rpm. The combina- tage of being able to be ‘water free’ as of a power plant based on multiple gas tion of working fluid and turbine speed air cooling can be used throughout the turbines as the cost of the ORC system leads to much reduced maintenance re- installation. is spread across multiple units. In addiquirements, as well as eliminating the Returning to our power plant capa- tion, thanks to ORC working fluid peneed for water in the process. ble of producing 40 MW at 40°C re- culiarities, the plant flexibility and efORC systems can use either directly ferred to in Figure 6, the addition of an ficiency at part load is not reduced. The or indirectly heat the working fluid. In ORC turbogenerator to the smaller gas ORC unit can be operated at between both cases the Waste Heat Recovery Unit (WHRU) installed in the gas tur10 Efficiency vs. Load Comparison bine exhaust system is a simple once through design, but in the indirectly 50 heated system, heat is transferred from 4 x 12.5-MW gas turbines with ORC the gas turbine exhaust to the ORC 40 working fluid via a secondary closed loop using a thermal oil. Directly heat30 ed systems offer better efficiency of the ORC cycle (see Figure 10 below) and 20 reduce the initial capital cost, while an 10 indirectly heated system allows for energy to be recovered from higher tem0 perature heat sources than a directly 0 10 20 30 40 50 heated system. MW Combining Gas Turbines + ORC Efficiency versus load comparison for a 50-MW class gas turbine and 4 x 12.5 MW class gas turbines in open cycle, with 4 x 12.5 MW class gas turbines with ORC at 40oC ambient temperature. to Maximize Performance As mentioned earlier, smaller gas

Efficiency (%)

Comparison of ORC System Efficiency for a Direct Heated and Indirect Heated System

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Efficiency vs. Load 100% Actual Efficiency/Nominal Efficiency

90% 80% 70% 60% 50% 40% 30%

Steam ORC

20% 10% 0% 0%

10%

20%

30%

40% 50% 60% 70% Actual load/Nominal Load

80%

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Direct comparison in efficiency versus load for similarly-sized steam turbine generator and ORC turbogenerator.

Efficiency vs. Load Comparison 50 40 Efficiency (%)

10 percent and 110 percent of its nominal load automatically, while still maintaining high efficiency even at partial load - as shown in the Figure 13, at 50 percent of the load, the ORC still has an efficiency of 90 percent of nominal full load efficiency). Obviously it is also possible to add an ORC system onto the larger gas turbine considered to improve efficiency but it is most likely in these cases that a configuration based on each gas turbine having its own ORC turbogenerator system will be needed. As for the multiple small units, the addition of the ORC system boosts both power and efficiency considerably. At nearly 47 percent net power output on a 40Â°C ambient day with all site losses accounted for, a 50MW class gas turbine with ORC offers a better efficiency than large (100MW) complex cycle gas turbines (which are quoted as having an ISO, zero loss efficiency of 44%). It is interesting to note that while the efficiency of the single larger gas turbine plus ORC is higher for station loads over 60 percent, at lower loads the efficiency of the multiple small units plus

In the example given in Figure 14, the ORC system is air-cooled, with the Air Cooled Condenser (ACC) designed for an average 30Âş C ambient temperature. The shape of the power output and efficiency curve can be altered by the design temperature used for the ACC: designing the ACC for the maximum ambient temperature will impact plant performance at lower temperatures, so it is important to consider and define the correct design point. Conclusions Combining multiple small gas turbines with ORC technology permits engineers to design a very load flexible power plant with optimal efficiency and emissions compliance across a wide load range. With no requirement for a water supply, such modular power plant potentially offer a simple way

4 x 12.5-MW gas turbines with ORC

20 10 0 0

MW Efficiency versus load comparison for a 50-MW class gas turbine in open cycle (blue line) with 4 x 12.5MW class gas turbines with ORC (red line) and a 50MW class gas turbine with ORC (green line) at 40oC ambient temperature

ORC is better. This suggests that for larger power plant of, say, 200 MW or 250 MW design output, a combination of 50 MW class and smaller 12.5 MW class gas turbines would give the optimum plant efficiency across the widest load range. The gas turbine plus ORC combination helps maintain a high output power and high net plant efficiency across a wide temperature range.

to meet the demands on the electricity grid caused by the large amounts of intermittent renewable power generation with high power plant reliability, availability and low maintenance in a cost-effective manner. By building such flexible distributed plant close to the actual load centers, investment in the power system infrastructure can also be reduced. www.power-eng.com

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ENVIRONMENTAL ISSUES

Author Tim Woodrow is the U.S. Commercial Manager for Hydrolox, a manufacturer of traveling water screens.

Hydrolox traveling water screens like the one in operation at Xcel Energy’s Wilmarth Station, Mankato, Minnesota, have very low associated O&M costs. Photo courtesy: Hydrolox.

application of a plant’s National Pollut-

ant Discharge Elimination System

(NPDES) permit. The 316(b) ruling provides a date (July 14, 2018) that dictates the timeline of compliance which all qualifying plants need to follow with regard to the renewal of their NPDES. Permit renewal is required every five years. Whether a permit is due for renewal before or after this date (or if it is working on an administratively extended permit) will determine the actions a plant must take over the upcoming period. Plants will have to submit a host of reports to state agencies, including section 122.21 (r2-8) among others. For permit applications after July 14, 2018, plants that withdraw more than 125 MGD must submit application with the appropriate reports (section 122.21 (r9-12)).These reports will enable the permit director to understand both the social and economic costs and benefits that a selected solution may have. If renewal is due before July 14, 2018, a plant will negotiate a separate timeline for compliance.

316(b): One Year Later

W BY TIM WOODROW

e are rapidly approaching the one year anniversary of the publication of the U.S. Environmental Protection Agency’s (EPA) new regulations under Section 316(b) of the Clean Water Act for Existing Facilities and New Units at Existing Facilities. According to the EPA, the final rule affects 544 existing power generating facilities that withdraw more than 2 million gallons of water per day (MGD) from U.S. waters and use at least 25 percent of the water they withdraw for cooling purposes. The rule requires that the location, design, construction, and capacity of cooling water intake structures reflect the Best Technology Available (BTA) for minimizing negative environmental impacts. Compliance with the rule requires all permit applicants to select an impingement compliance approach from seven options. Applicants with actual intake flows exceeding 125 MGD must first complete and file several study reports 34

(§122.21(r9-12)) that will provide permit directors with the engineering, biological, and economic information necessary for an entrainment BTA determination. Following this determination, these applicants will then select their chosen impingement compliance approach from the BTA compliance options. The required studies, as well as the timely selection of a compliance option, will be a challenge for the industry, requiring the latest information on fish protection technologies (cost and performance); biological sampling methods and interpretation of results; and practical approaches and supporting information for assessing economic social costs and benefits.

WHERE ARE WE NOW? One of the fundamental requirements of the final rule is the parameters under which a plant must select a BTA to reduce the impact of impingement and entrainment. The timing of compliance also represents another major change from the draft rule. Compliance is tied to the renewal

SCREEN OPTIONS In all likelihood, installing and optimizing traveling fish protection screens will be the lowest cost option for the majority of power plants. However, there is concern that operating traveling water screens whenever drawing water will dramatically increase operational and mechanical costs. This is where the industry may be missing an opportunity. While plants are preparing to submit their permit applications with the required data, they must ensure that they have studied the various BTA options from a mechanical performance perspective. Currently, power plants operate their www.power-eng.com

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ENVIRONMENTAL ISSUES screens two to three times a day, about 20 minutes at a time, for a total of about an hour a day. Even with this reduced usage, they are still spending anywhere from $20,000 to $50,000 a year to keep the screens operating. Under the new rule, any time a plant turns on its water circulation pumps, it must also rotate its screens. In order to comply with the rule, then, these plants must now operate their screens up to 24 hours a day, seven days a week; this has many plant operators worried about costs. The total cost of a screen is not entirely accounted for by its up-front capital expenditure. Operational and maintenance costs must also be added into this equation. Traditional screens are driven by large side chains which represent a large maintenance burden. A new screen technology has made it possible to eliminate this chain, making the screen nearly maintenance-free, which can

dramatically lower maintenance costs, even when screens must run 24/7. There are pros and cons related to each BTA, pre-approved and streamlined, and their associated costs and benefits. Pre-approved BTA options include the use of an existing closed-cycle cooling system, or the installation of a new one. This can be very expensive to retrofit with costs ranging from $50 million to $300 million. Another pre-approved option involves the design of a cooling water intake structure that has an actual through screen velocity lower than 0.5 feet per second (ft/s), which would involve increasing the surface area of the screening system by a factor of two- to five-fold, an undertaking with significant associated costs. The streamlined approach has a few options. The first option involves the installation of modified traveling water screens, perhaps the lowest capital-cost

solution. Another streamlined option requires facilities to achieve an actual through screen velocity of 0.5 ft/s by increasing the screening area or via unit retirements. Additionally, the two streamlined options above can be combined to create an additional option for the streamlined approach. The final BTA option requires facilities to maintain less than 24 percent mortality in aquatic life as a result of impingement. This option would require a plant to install modified traveling screens, as well as monitor and report their impingement mortality every month for the life of the plant—an option so tedious and expensive that most will not consider it.

316(B) IMPACT ON POWER PLANTS Power plants have been approaching 316(b) in different ways. First and foremost, plants are assessing where they

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are on the NPDES timeline to determine the urgency of compliance and whether their facilities fall in the impingement or entrainment category. Plants with permit renewal deadlines that fall before July 14, 2018 will negotiate a separate compliance timeline, but those with permits due for renewal after July 14, 2018 will need to submit their data/ reports and select one of the approved BTA technologies, as well as their entrainment solutions, if applicable. After reviewing data from studies and analysis, some plants have already proactively installed fish screens and tested them for both aquatic protection and operating costs so that they have a clear understanding of the costs and work associated with living with traveling fish screens in a post-316(b) environment.

Adaptive Brush Seal Solutions for Air Preheaters

316(B) IMPACT ON STATE REGULATORY AGENCIES Just as power companies and individual plants are assessing their positions and the workloads ahead of them, so too are state agencies. State agencies have been tasked with enforcing numerous new EPA regulations, including MATS and the Clean Power Plan under the Clean Power Act. Section 316(b) is just another regulation to be considered in this mix. Response from state regulators has been mixed. Some regulators are only just getting up to speed on the regulation, while some are even proactively writing 316(b) regulation into their current NPDES permits. Others are asking the EPA for an extension beyond July 14, 2018. For the majority of states, the expectation is that the state permit writer will follow the guidelines as laid out in the rule. The relationship that a plant has with their local state permit writer will be crucial in determining the smoothness of the compliance process.

WHERE DO WE GO FROM HERE? Plants are currently engaging in contracts with independent consultants to prepare the paperwork and conduct the studies necessary to submit their applications at the appropriate times. As mentioned, the compliance schedule for facilities is driven by where their NPDES permit renewal date falls in relation to the July 14, 2018 deadline. All facilities are required to comply with one of the seven standards of impingent mortality. Proactive plants will install test equipment ahead of their submission timeline to determine the most cost effective and reliable compliance option.Â With the modern technology available, plants will actually have the opportunity to reduce their operation and maintenance costs while meeting 316(b) compliance guidelines, depending on the BTA they choose. www.power-eng.com

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Pearl GTL Plant located in Qatar manufactures GTL base oils. Source: Shell

TURBINE OILS:

A Key Factor in System Reliability

BY ROB PROFILET, PH.D.

n a recent Shell global survey, turbine oil end users indicated that their biggest concern was unplanned downtime during turbine operation. The cost of downtime can be significant if a power company is unable to provide power. Todayâ&#x20AC;&#x2122;s turbine systems are operating under increasingly severe conditions including wider temperature variances due to stop/ start cyclic operation, which has resulted in some instances in varnish formation on critical turbine component surfaces. 38

Temperature fluctuation in the turbine oil can result in oxidation and thermal degradation initially caused by elevated temperatures of the oil, followed by the deposition of varnish on critical valves as the oil cools to lower temperatures. Resulting stuck valves can in turn cause unplanned downtime, added maintenance costs, and lower productivity. The survey also indicated that end users are interested in extended oil drainage service intervals to reduce maintenance. In addition, the oil must provide adequate

rust and corrosion inhibition, separate water quickly, be compatible with seals, not foam, and be readily filterable. These challenging operating requirements and the desire to extend the lifetime of the turbine oil require robust turbine oil technology in combination with a good oil maintenance program. Turbine oil formulations must possess very specific properties if the oil is to provide adequate protection for the turbine. To prevent metal-to-metal contact, oils need to have the correct viscosity for www.power-eng.com

Author Rob Profilet has 22 years of experience in the field of industrial lubricants. He serves as Shellâ&#x20AC;&#x2122;s Product Application Specialist for industrial products for the Americas.

support loads carried by the bearings. The oil must also act to some degree as a coolant. The internal surfaces inside a turbine become very hot, and the oil must absorb this heat without thermally degrading or oxidizing prematurely.

FORMULATION OF TURBINE OILS

a given application in order to provide a good oil film for bearings. Oils must release air rapidly to help prevent cavitation, but must also not cause excessive foaming. Rust and corrosion inhibition is a necessity to ensure all key components of a system are protected. In steam turbines, or in other systems where water contamination can be a concern, the turbine oil must separate water very rapidly. If water cannot separate from the oil, an oil-in-water emulsion can form which will interfere with the oil film needed to www.power-eng.com

So how is turbine oil formulated? Unlike motor oils, which may contain 20 to 30 percent additives, typical turbine oil formulations contain approximately 99 percent base fluid and only one percent additive. Both the base oil and additive play very critical roles in the performance of the lubricant. The additive itself is a delicate balance of antioxidants, rust and corrosion inhibitors, demulsifiers, defoamants, and pour point depressant. In the case of turbine systems with gears, an anti-wear additive is often present as well. The right combination of additives and base oil is critical to minimize the impact of oxidation and thermal degradation which can lead to the formation of sludge and varnish. The most common lubricants used in gas, steam, and combined-cycle turbines today are based on formulations utilizing mineral oils in combination with an additive system. The mineral base oils utilized are API Group I, II, or III. The base oil can have a significant impact on the performance of the turbine oil. When combined with appropriate additive technology, Group II and III base oils exhibit extended oxidation life compared to turbine oils formulated with Group I base oils. Turbine oils formulated with Group III base oils have an advantage over those formulated with Group II base oils because they have a naturally higher viscosity index. This higher viscosity index helps maintain the thickness of the oil film at the bearing during times of elevated temperatures. Group III oils also help provide

enhanced surface properties in the finished lubricant.

GAS TO LIQUID BASE OILS Base oil technology has evolved recently to help improve turbine oil performance. Shell recently introduced Gas to Liquid (GTL) base oil which is considered an API Group III base oil. The use of Shell GTL technology represents an exciting step change in technology for turbine oils. Shell GTL technology involves the conversion of natural gas into high-quality products including transport fuels, waxes, chemicals, and lubricants. Research into GTL for Shell began in Amsterdam in 1973, and now after many patents, is produced in Qatar. Shell GTL base oil has been shown to enhance motor oil formulations with better volatility control, better low temperature performance, and enhanced oxidation stability. The benefits of GTL technology are a natural fit for turbine oil formulations. Enhanced oxidation protection helps the turbine oil last longer and resist the formation of oxidation byproducts which ultimately lead to the formation of varnish. Rapid air release properties of GTL base oils also enable the turbine oil to operate more efficiently by minimizing the chance for the oil film to be broken, which is critical in the lubrication of the bearings. GTL base oils also have a higher viscosity index, which helps maintain the optimum viscosity and film thickness required for the bearings in a turbine across a wider range of temperatures. Maintaining film thickness and reducing the formation of varnish can help reduce bearing temperatures.

OIL ADDITIVES Although small in quantity, the additive used in turbine oils has a big job to do. Turbine oil additive systems are designed to minimize foam, provide rust 39

and corrosion protection, and help separate water very quickly so it can be removed. Because turbine oils are expected to last a long time (7+ years for gas turbines and up to 20+ years for steam turbines) the additive must contain a robust antioxidant system.

THE PERILS OF VARNISH Due to the high operating temperatures found in turbine systems, improperly formulated oils can thermally degrade, oxidize, and form varnish. Varnish is found on critical turbine surfaces and starts as a soft film, gradually hardening into a lacquer which is not easily removed. The lacquer can act as an insulating film that interferes with heat transfer. It can also trap particulates such as wear metals. In addition, the varnish can cause valves to stick, causing the turbine not to start. The varnish layer which forms on bearings takes up critical clearance space for the oil film, which can result in higher temperatures and the formation of more varnish. Varnish precursors form when polar long chain acids, aldehydes, and ketones form in the oil from oxidation and thermal degradation of the lubricant. These precursors eventually combine or react with each other and form longer chain polymeric species. The oil will hold this material in solution until a saturation point is reached and the resulting “sludge” drops out on cooler parts of the system (often during shutdown). Overtime, the sludge turns into varnish and eventually a lacquer as temperatures increase.

IN THE LAB Once a fluid has been developed, several tests are conducted in the laboratory to assess the performance of a product. Common physical property tests such as viscosity, flash point, pour point, and density are measured along with performance tests. Performance 40

tests include water separation properties, resistance to rust and corrosion, air release, filtration performance, foaming tendencies, and thermal and oxidation stability tests. A common method used to measure resistance to oxidation is the ASTM D943 Turbine Oxidation Stability Test. This test is commonly listed on supplier Technical Data Sheets. In this test, a mixture of oil and water is heated to 95°C in the presence of a catalyst and bubbling oxygen to expedite the oxidation process. The oil is monitored by total acid number, and the test is stopped when oils reach 2.0 mg KOH/g. The more hours in this test the

A severe method to measure thermal stability is the MAN Thermal Stability Test. The test is conducted by heating the test oil in a static oven at 180°C for a period of two days. The amount of sludge formed is then measured, which helps to assess the thermal stability and short-term deposit resistance when the oil is exposed to very high temperatures.

better; long life turbine oils will have a value of >10,000 reported hours. There are other oxidation tests which can also assess turbine oil performance. These include ASTM D4310 (1000 hour TOST) which measures sludge formation, ASTM D2272 Rotating Pressure Vessel Oxidation Test (RPVOT), and the Dry TOST Test (ASTM D7873). The Dry TOST Test (ASTM D7873) promotes the oxidation of the turbine oil in the presence of heat (120°C), metals (steel and copper coils), but no water. The test is conducted for a period of 1008 hours, and is designed to measure the sludging tendency of the fluid by measuring the RPVOT retention and insoluble oxidation products. The test is a useful method to predict turbine oil performance in the field.

product. Field demonstrations allow for careful monitoring of the fluid in real-world applications. The fluid is introduced and monitoring is conducted on a scheduled basis that is agreed upon with the end user. All turbine oils should be subjected to a proactive oil analysis monitoring system. There are many published turbine oil condition monitoring guidelines available from industry bodies such as ASTM and ISO. Original equipment manufacturers (OEM) also publish guidelines to help the end user monitor the turbine oil and get the most efficient performance. Lubricant suppliers will also provide guidance to help suggest a schedule for testing. Test schedules will often include viscosity, total acid number (TAN), water

IN THE FIELD After laboratory testing is completed, turbine oil suppliers will often conduct field demonstrations of their Thermal stability in turbine oils can vary based on results of the MAN LTAT thermal stability test. Source: Shell Global Solutions

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Typical Testing Schedule for Turbine Oils

Test

Steam Turbine

Gas Turbine

Suggested Limits

Viscosity

Quarterly/Bi-annual

Quarterly

+/- 5% of fresh oil value

Total Acid Number (mg KOH/g)

Quarterly/Bi-annual

Quarterly

Caution: 0.1-0.2 over new oil value; Warning 0.3-0.4 over new oil value

Water Content (KF, ppm)

Quarterly

<0.1% for steam; <0.05% for gas

Elemental Analysis (ICP)

Quarterly

Check contamination

Oil Cleanliness (ISO 4406)

Quarterly/Bi-annual

Quarterly

Follow OEM Limits

RPVOT (min)

Annual

Quarterly

<25% of fresh oil

Demulsibility (ASTM D1401)

Annual

---

>40-37-3 (40 minutes)

MPC or QSA (varnish formation)

---

Quarterly

<40 MPC; <60 QSA

Foaming (mL-mL)

Annual

450/10 max

Turbine oils should be tested on a regular basis to help extend the life of the fluid and the system. Source: Shell Global Solutions

Predicting the Onset of Varnish Normal <15

Monitor 15-29

Abnormal 30-40

2 Critical >40

MPC Turbine oils can be tested using the MPC test to help predict the onset of varnish. Increasing varnish potential results in a darker filter patch. Source: Shell Global Solutions

content, elemental analysis by ICP, oil cleanliness (particle count), RPVOT, demulsibility, foam performance, RULER Test, and either MPC (membrane patch colorimetry) or QSA (quantitative spectrophotometric analysis) to assess varnish potential in the fluid. Varnish potential screening methods have been successful in identifying a system with a high potential to varnish by isolating insoluble oxidation products and measuring their concentration in the system. By assigning a rating system, an end user can take different courses of action to help protect their system. If a high rating is observed, there are many systems available which can be www.power-eng.com

used to help remove varnish precursors from turbine oils or other lubricating oils. Popular methods include the use of electrostatic filters, balanced charge agglomeration systems, electro-physical separation processes (ESP), depth filtration, and filters which minimize electrostatic discharge. The best route to minimize varnish formation involves a two-pronged strategy. First, a high-quality turbine oil should be selected. The oil should not only have excellent oxidation resistance, but should also be resistant to deposit formation. Second, a proactive oil monitoring program can go a long way in minimizing problems resulting from oil degradation, extending the life

of the oil, and providing a higher level of protection for the system. Downtime and unplanned maintenance can be reduced or eliminated.

CONCLUSION Shell recently introduced a new line of turbine oils which provide a very high level of performance for steam, gas, and combined-cycle turbines. The technology is based on the use of Shell GTL Group III base oils in combination with a specially developed additive system. Testing in the laboratory and in the field has shown that these products have a very high resistance to oxidation and thermal breakdown, minimizing the formation of sludges and varnish on critical turbine surfaces. These products have very rapid air release and are low foaming, helping to improve the overall efficiency of the turbine operation. The use of Shell Turbo S4 X or Shell Turbo S4 GX (for turbines requiring protection of gears) in combination with a suitable oil-monitoring program can help to extend the life of critical turbine components and help extend the life of the turbine oil. This can result in lower costs, less unplanned downtime, and higher efficiency. 41

POWER PLANT OPTIMIZATION

Author Brad Buecker is a process specialist with Kiewit Engineering and Design Company in Lenexa, Kansas.

Maintaining Maximum Efficiency in Power Generation Units

QB = heat input to the steam generator QC = heat extracted in the condenser WP = work done by the feedwater pump (usually negligible in this particular calculation) The diagram also indicates a key component of the second law; for any process that produces work, not all of the heat input can be utilized for work, some heat must be extracted as waste energy. We will later examine how this thermodynamic aspect makes condensers, and proper operation of them, so important for power generation. In the meantime, letâ&#x20AC;&#x2122;s consider another important issue from Figure 1. If the steam from this simple system were to be immediately injected into a turbine, very little work would occur, as the steam would immediately begin condensing to water upon passage through the blades. For this reason among others, all utility steam generators include superheaters to raise the steam temperature well above saturation and allow much more work from the turbine. Even so, the net efficiency of Rankine-cycle only plants ranges from 1/3 in the least efficient plants

heat losses, friction, and other mechanisms, the theoretical work available from the turbine (W T) can be approximated by the following straightforward equation. BY BRAD BUECKER, CONTRIBUTING EDITOR W = m(h â&#x20AC;&#x201C; h ) Eq. 1, where T 2 1 irtually everyone in the m = mass flow rate of steam through power, chemical pro- the turbine cess, and other indush1 = enthalpy of turbine exhaust steam tries is no doubt aware h2 = enthalpy of turbine inlet steam of the greatly expanded efforts to lower carbon dioxide emisA Basic Rankine Cycle sions from industrial sources. This concern continues to lead increased efforts QB into maximizing plant efficiency both through good operating principles and through design improvements. This artiHigh-Pressure Steam cle examines several of these issues with Boiler regard to steam-generating facilities.

AN OVERVIEW OF THE RANKINE CYCLE Power production via steam generation to drive a turbine is based on the Rankine cycle, whose fundamental outline is shown below. Even this simple diagram (Figure 1) clearly illustrates several fundamental aspects from the first and second laws of thermodynamics. First, and for the time being ignoring entropy increases due to 42

Turbine Turbine exhaust

Feedwater

FW Pump

Condensate

Condenser

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Fouled Condenser Tubes 2

to perhaps a bit above 2/5 for the most efficient plants. The primary reason regarding this seemingly low efficiency is that the usable energy is contained in the superheat of the steam, perhaps 500 to 600 Btu/lbm is not as large as the steam latent heat, approximately 1000 Btu/lbm. We will examine several examples shortly, when examining condenser and heat exchanger cleanliness. This then is one aspect, among several, that is driving industry towards higher efficiency machines. The two processes that stand out are combined-cycle power generation and combined heat and power (CHP) or co-generation. We will consider CHP/co-generation first. The previous example from the Rankine cycle showed that much heat is lost during the condensation process in the condenser. This lost energy represents the latent heat of the exhaust steam. However, if in place of the condenser which simply exhausts the heat to a cooling tower or other heat sink, the steam is transported to heat exchangers to drive chemical processes or even simply to warm water for district heating systems, much of the latent heat is productively utilized. Consider 100,000 lbm/hr of saturated steam flowing to a heat exchanger with water as the process fluid, say for building heat. Energy transfer from condensation alone could warm approximately 3,000,000 lbm/hr of the water from 70oF to 100oF. On the flip side, heat is a requirement for www.power-eng.com

such devices as absorption-refrigeration to keep condensers and heat exchangers chillers, which are common devices for clean from chemical and biological decooling large office buildings. Again, la- posits, and also operating properly from tent heat is a potential source of energy for a mechanical perspective to avoid costly impacts. We will examine heat transfer these systems. Net efficiencies of up to 80 percent issues below, starting with a non-conhave been reported for co-generation pro- densing steam turbine. Equation 1 approximates the heat cesses. The power industry continues to see steady installation of combined-cycle transfer in an ideal steam turbine, while power plants, which also offer increased in actuality turbines are typically 80 to efficiency. These plants, of course, use 90 percent efficient. To simplify the discombustion turbines for partial power cussion, we will consider an isentropic production with heat recovery steam gen- (no energy losses) turbine, as this examerators (HRSG) for additional power gen- ple is still quite sufficient to outline the eration from a steam turbine or turbines. principles intended. Conditions for the This is truly a combined cycle process, as non-condensing steam turbine example the HRSGs operate on the Rankine cycle are: Main Steam (Turbine Inlet) Pressure – while the combustion turbines operate on the Brayton cycle. Maximum efficien- 2000 psia Main Steam Temperature – 1000oF cies in some units have now topped 60 Turbine Outlet Steam Pressure – Atmopercent, which is immensely better than efficiencies for some of the old coal plants spheric (14.7 psia) The steam tables show that the enthalthat are still operating. From a combustion turbine aspect, the key limiting factor py of the turbine inlet steam is 1474.1 Btu per pound of fluid (Btu/ to efficiency is the para“This is truly a lbm). Thermodynamic sitic power requirement for the inlet air compres- combined cycle calculations indicate that the exiting enthalpy from sor. But much energy is, process, as the the turbine is 1018.4 Btu/ of course, regained by HRSGs operate lbm (steam quality is converting the combus86%). Per Equation 1 tion turbine exhaust heat on the Rankine the maximum unit work into steam for Rankine cycle while the available from this ideal cycle power generation. combustion turbine is (1474.1 Btu/ But, even with these design efficiency improve- turbines operate lbm – 1018.4 Btu/lbm) = 455.7 Btu/lbm. To put ments, it is still very im- on the Brayton this into practical perportant to maintain top cycle.” spective, assume steam efficiency from an operating standpoint. This is particularly true flow to be 1,000,000 lb/hr. The overall when it comes to proper cooling water work is then 455,700,000 Btu/hr = 133.5 megawatts (MW). and steam generator cleanliness. At this point, if the exhaust steam were transported for co-generation or CHP KEEP THE HEAT purposes, excellent efficiency would be EXCHANGERS CLEAN A thread through all of the technol- possible. However, in the power industry ogies mentioned above is that the exsteam condensation is a very important haust heat from the steam generation step. Therefore, consider a second examprocess must be transferred in one or ple, where the unit has a condenser that more heat exchangers. It is paramount reduces the turbine exhaust pressure to 43

POWER PLANT OPTIMIZATION

1 psia (approximately 2 inches of mercury). Again assuming an ideal turbine, the enthalpy of the turbine exhaust is 904.9 Btu/lbm. The unit work output equates to 1474.1 – 871.0 = 603.1 Btu/ lbm. At 1,000,000 lb/hr steam flow, the total work is 603,100,000 Btu/hr = 176.7 MW. This represents a 32 percent increase in available work from the previous example. Obviously, condensation of the steam has an enormous effect upon turbine efficiency. One can also look at this example from a physical perspective. Calculations indicate that the steam quality at the turbine exhaust pressure of 1 psia is 77 percent. (In actuality, this would be excessive moisture that could damage low-pressure turbine blades. Techniques such as steam reheating are common for reducing moisture in the low-pressure turbine.) This means that 23 percent of the steam has condensed to water. However, the remaining steam takes up a specific volume of 257 ft 3/lbm. The corresponding volume of water in the condenser hotwell at saturation temperature is 0.016136 ft 3/ lbm. Thus, the condensation process reduces the fluid volume nearly 16,000 times. The condensing steam generates the strong vacuum in the condenser, which actually acts as a driving force to pull steam through the turbine. (The strong vacuum also pulls in air from outside sources, where excessive air in-leakage can seriously affect heat transfer.) In the next example, we can see why it is important to maintain proper cleanliness in condensers and heat exchangers. Consider again a condensing turbine, but where waterside fouling or scaling (or excess air in-leakage) causes the condenser pressure to increase from 1 psia to 2 psia. Thermodynamic calculations show that the work output of the turbine drops from 603.1 to 569.2 Btu/lbm. So, at 1,000,000 lb/hr steam flow, a 44

rise from 1 psia to 2 psia in the condenser backpressure equates to a loss of 33,900,000 Btu/hr or 9.9 MW of work. This is a primary reason why proper cooling water chemical treatment and condenser performance monitoring are very important. Severe fouling may require a reduction in unit load. If this occurs on a hot summer

Fouled Cooling Tower Film Fill

day with emergency power pricing in effect, the financial consequences can be enormous. Techniques continue to emerge to improve condenser, heat exchanger, and cooling tower performance. These include more effective biocides, improved cooling tower film fill, more rugged condenser tube materials, and enhanced instrumentation for monitoring physical and chemical operating parameters. Similarly, for co-generation and CHP facilities it is important to keep heat exchangers free of deposits and corrosion to ensure maximum efficiency and equipment availability. Often, cooling towers are neglected because they may be isolated from the main equipment. Improper chemistry control in chillers and building heat systems may lead to severe corrosion. The list goes on.

DON’T FORGET ABOUT THE STEAM GENERATOR Although we have focused upon methods to maximize heat extraction from the steam generation process, it is important to remember that heat input efficiency should be maximized as well. Poor makeup water treatment and water/steam chemistry programs can lead to deposition and corrosion in steam generators. While boiler tube failures often result from poor chemistry, even in units with seemingly good treatment programs, problems can arise. The most common deposit on steam generator tubes and internals consists of iron oxide particulates that are generated in the condensate/feedwater system. (The concentration can be very large in systems equipped with air-cooled condensers.) So, it is absolutely vital to operate with the proper feedwater chemistry, and to have the ability to immediately detect impurity ingress from a leaking condenser tube or other source. [2] For units with ACCs, a condensate particulate filter is an absolute must. Periodic removal of boiler tube deposits by chemical cleaning is often a necessary procedure to improve heat transfer. Not only will deposits reduce heat transfer in general, they will also cause an increase in tube metal temperatures which can lead to accelerated metal deformation known as “creep.” Finally, and often most important, is that some deposits, and most notably transported iron oxides, are porous and can allow impurities in the bulk boiler water to concentrate underneath the deposits. Local and rapid corrosion may be the result. In fact, the Electric Power Research Institute (EPRI) now recommends a normal (and very low) limit of 2 parts-per-billion for chloride and sulfate in condensate, precisely because these impurities, and chloride in particular, can generate severe under-deposit corrosion in the steam generator. www.power-eng.com

For info. http://powereng.hotims.com RS#13

Author Andrew Markle is Senior Engineer for NAES Engineering Services

WHAT WORKS

Risk Review Leads to Alternative Plan for Jamaica Fuel Conversion the containers would then be loaded onto flatbed tractor-trailers using truckmounted cranes, and transported two kilometers inland to the plant. They would be stockpiled plant-side, and the LNG vaporized to a gaseous state by skid-mounted electric vaporizers. Once the containers were empty, they would be sent back to the port to be refilled. While this solution would present obvious operational challenges, it would likely be the quickest way to repower the plant and would also reap the financial and environmental benefits of burning LNG. Option 2: Large-Quantity LPG Delivery and Refrigerated Tank Storage This solution would be based on unloading liquefied petroleum gas (LPG) from a large-volume refrigerated vessel into a large, stationary, refrigerated tank(s) located at the port-side terminal – or transported to a plant-side tank(s) via a cryogenic pipeline. In addition to comparing the merits of the LNG and LPG solutions, we were asked to advise on which LPG tank location – port-side or plant-side – presented less technical, financial and safety risk.

allowed a larger Combustion/Explosion Hazard Area (CEHA) that would likely meet worst-case requirements. (We used applicable Jamaican fire codes that were based on standards of the U.S. National Fire Prevention Association (NFPA) Code, Sections 57 through 59, for handling of LPG and LNG.) The relatively congested areas adjacent to the Bogue Plant, on the other hand, would likely require double-walled tank construction as a safety precaution. Using a doublewalled tank would both lengthen the construction timeline and increase cost. The use of portable ISO LNG containers is common but not at this scale. In addition, transporting them overland presented significant safety risk. Staging, filling, transporting, unloading, purging and inspecting a proposed fleet of 350 ISO containers – based on consumption of 22 containers per day – would likely constitute a ‘fatal flaw.’ We investigated the market for delivering relatively small quantities of bulk LNG in the Caribbean and found it to be still in the early stages of development. We did identify two suppliers that are preparing to offer such service to the region in the near term, but found no companies currently able to deliver bulk LNG at this small a scale. Although it lay outside the scope of this review, we advised the client to complete a thorough financial and technical due diligence of potential suppliers – and sign a firm supply agreement with a credit-worthy supplier – before moving ahead with any plan that relied on bulk LNG delivery.

A UNIQUE SET OF CHALLENGES

OUR RECOMMENDATION AND LOGIC

The geographical complications – an island location with an inland plant requiring both port-side and plant-side facilities – in addition to the regional market conditions and economics made this an interesting assignment. The portside area offered a fair amount of vacant property for siting of storage tanks. This

While we advised the client that either plan was feasible as proposed, we recommended significant modifications to both. For the LNG solution, we recommended relatively small-scale LNG import; extensive due diligence before contracting with any supplier; port-side storage; and overland transport of the

BY ANDREW MARKLE, P.E.

s many who work in the Caribbean energy markets know, Jamaica has been trying for years to import liquefied natural gas (LNG). Unfortunately, suppliers have deemed the Jamaican market too small to support a full-scale LNG storage and regasification facility, so the need has remained unmet. To answer the call, Marubeni, a stakeholder in the Caribbean power-generating industry asked our Engineering Services team to review the technical and safety risks of two alternate plans for refueling the Bogue Power Station, a light distillate oil-fired, combined-cycle facility near Montego Bay, Jamaica. (Note: As one of several investors in Jamaica Public Service Co. Ltd. (JPS), Marubeni engaged NAES for an independent study and does not speak for the other investors or for JPS.) Designed for a net capacity of 120 MW, the refueled Bogue plant is equipped with two GE MS6001B gas turbines, two HRSGs and a single steam turbine. Although it did not affect the scope of this review, Marubeni elected to retain the capability to operate on oil as a backup in the event of disruption to the LNG supply chain. Option 1: Small-Quantity LNG Ship Delivery and ISO Container Overland Transport This plan would be based on smallscale ship delivery of LNG with overland transport via a fleet of small-volume ISO containers. Once the LNG was pumped from the ship to the containers, 46

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fuel to the plant in a gaseous state via pressurized pipeline. For the LPG option, we favored the large-volume, refrigerated, port-side LPG tank(s) with a port-side vaporization facility that would also transport the fuel to the plant in gaseous form via pressurized pipeline. Our modification of the LNG option called for replacement of overland transport in ISO containers with a pressurized, ambient-temperature pipeline. ISO containers at the scale required to supply Bogue would introduce substantial safety risk to personnel as well as considerable operational complexity. While the infrastructure for delivering and receiving bulk shipments of LNG in the quantities required to operate Bogue could be erected in the near term, no vendor we contacted was able to make such shipments to the port of Montego Bay at the time of inquiry. However, if a suitable small-scale supplier could be found, we advised that keeping the LNG terminal facility small would reduce the construction schedule from an estimated two-year duration to a single year. As for the proposed LPG plan, the established supply chain for delivering LPG in bulk quantities to the Caribbean market eliminates much of the risk posed by an LNG solution, at least in the near term. By opting for the port-side storage tank location, the client could likely achieve compliance (pending a more detailed engineering investigation) with a single-walled tank design due to the larger expanse of available CEHA. This would also shorten the construction timeline and substantially reduce capital expense. Vaporizing the fuel port-side

would eliminate the need for a cryogenic pipeline with all of its attendant capital and O&M expenses.

AN ALTERNATIVE LPG SOLUTION In response to our recommendations, the client requested an estimated end-toend construction time to fabricate, erect and bring online a 13,000 m3 refrigerated, vertical-cylinder LPG tank based on three possible configurations: single-wall, double-wall and full-containment. Our estimates were to reflect current market conditions and any existing bottlenecks that could impact construction time. Based on our consultation with three tank suppliers (one of which is currently doing business in the Caribbean market) and our own experience, we proposed a third alternative: a port-side installation of 10 cylindrical, horizontally erected bullet tanks measuring 21 x 180 feet, each with a capacity of 1,400 m3 at 80 percent full. The estimated construction time would compare very favorably with estimates for a vertical cylinder of singlewall, double-wall or full-containment construction: • Refrigerated bullet tanks: 10 x 1,400 m3 = 8 to 12 months • Single-wall vertical cylinder: 1 x 13,000 m3 = 18 months • Double-wall vertical cylinder: 1 x 13,000 m3 = 24 months • Full-containment vertical cylinder: 1 x 13,000 m3 = 24 months With the bullet-tank solution, the foundation-building and tank fabrication could proceed concurrently, which would substantially reduce construction time. In addition, several tank fabricators located on the U. S. Gulf Coast could ship directly to Jamaica. We also recommended mounding the bullet tanks with an engineered soil, sand

A portside tank location, where the surrounding Combustion/Explosion Hazard Area encompasses uninhabited property and water.

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and gravel foundation, and moisture barrier to improve protection from fire, hurricanes and earthquakes. While this installation would have a larger footprint than the single large tank, we believe the CEHA would still be confined to the vacant property and adjacent water at portside, although a more detailed engineering investigation would be required to verify this. To confirm feasibility of the bullettank solution, we researched a similar installation currently under construction on the island of St. Thomas in the

Mounding of LPG bullet tanks (as shown in this example) to further reduce risk from fire, hurricanes and earthquakes.

U.S. Virgin Islands, and forwarded our findings to the client. We also noted that larger bullet tanks are available – up to 5,000 m3 capacity with dimensions of 40 x 160 feet. However, we have not seen tanks this large used on land and do not know of many shops that have the capability to roll steel for a 40-foot-diameter pressure vessel.

THE CHOSEN SOLUTION Ultimately, the client elected to go with an LNG solution, which was likely prompted by fuel-pricing analysis that lay outside the scope of NAES’ investigation. Based on small-quantity ISOcontainer shipment, the fuel would be vaporized at the terminal and transported to the plant via a pressurized, ambient-temperature pipeline. To facilitate the supply, Marubeni has contracted with a vendor to transport the ISO containers weekly from its small-scale liquefaction facility in Florida. 47

PRODUCTS Battery thermal protection

35µF. Housed in size A cylindrical cases measuring

producing highly accurate and reliable cryogenic

E Connectivity’s business unit, TE Circuit

54mm (L) x 36mm (OD) x 5.1mm (P1), the RoHS-

flow measurement, a direct result of the emphasis

Protection, introduced the new MHP-TAM series.

compliant series is rated for operating tempera-

they put on extensive research and development.

The MHP-TAM device features an ultra-low-profile (L:

tures spanning -40°C to +105°C and exhibits long

5.8mm x W: 3.85mm x H: 1.15mm max.) package

lifetime performance of 100,000 hours at rated

Turbines Inc. Info http://powereng.hotims.com RS# 403

and a high (9VDC)

voltage and 70°C.

rating. The devices

AVX Corp. Info http://powereng.hotims.com RS# 401

Front-end power supply

a choice of two

different levels of

Corrosion protection

put front-end power supply designed in a sub-1U

current-carrying

ortec Corp. introduces environmentally safe

horizontal package for integration into a Tectrol

BioCortec range of corrosion control products.

power shelf or other end-user system. The power

BioCortec is a green response to hazardous oil

supply includes secondary isolation from chassis

in the series offer

capacity and multiple cut-off temperature ratings. The device provides

1800-48 1800W output power, 48VDC out-

a space-efficient thermal cutoff (TCO) solution that

>1500VRMS with output adjustable to 54VDC for

helps designers meet the demanding peak-current

PoE (Power over Ethernet) requirements and is

requirements of consumer products.

suitable for ATCA (Advanced Telecommunications

Utilizing innovative metal hybrid PPTC technol-

Computing Architecture) applications. This high reli-

ogy, the MHP-TAM device combines a bimetal pro-

ability power supply features universal AC input, ac-

tector in parallel with a PPTC (polymeric positive

tive PFC and I2C Interface for advanced status and

temperature coefficient) device. In battery applica-

control functions.

tions, the MHP-TAM device helps provide resetta-

The Tectrol TFE-1800-48 offers a very compact

ble over-temperature protection to shut down the

footprint of just 1.60-inch x 4.00-inch x 11.00-inch

battery when a fault is detected. The device rests

derived corrosion preventatives and offers eco-ef-

(40.64 x 101.60 x 279.40 mm), provides full power

when the fault is removed. The devices in the MHP-

ficient, compostable and biodegradable solutions

output of 1800W over the range 180-264VAC and

TAM series feature different open temperatures,

made from sustainable materials. Utilizing new

1000W over the range 90-180VAC and offers high

ranging from 72°C to 90°C (typical), which are ap-

technologies, Cortec is continuously developing

efficiency of 85 percent minimum at 90 VAC.

propriate for the battery market. They also offer two

biobased chemicals.

Tectrol Info http://powereng.hotims.com RS# 404

levels of hold currents: low-current (approximately

These products do not destroy the natural bal-

6A at 25°C) and high-current (approximately 15A

ance of the environment, are functionally superior

at 25°C).

to conventional petroleum derived products as well

TE Circuit Protection Info http://powereng.hotims.com RS# 400

as cost efficient making them a far more economical solution.

Compact digital thermocouple gauge

he Sensor Connection expanded its line of tem-

Cortec Corp. Info http://powereng.hotims.com RS# 402

Film capacitor series

perature measurement and control instrumenta-

tion with the addition of the model DPG-SD-2 series dual channel digital Type

VX Corp. launched the new FRC Series me-

Turbine flow meter

K thermocouple tem-

perature gauge.

of capacitance and voltage values in ad-

of its cryogenic turbine flow meter for bulk and mi-

sor-based

dition to self-healing

cro-bulk transports.

packaged in a compact

Turbines Inc.’s

52mm O.D. round hous-

dium power DC-link film capacitors, which feature a wide range

properties. Designed for use

ectrol announce the availability of their TFE-

urbines Inc. expands its comprehensive cryogenic monitoring capabilities with the availability

cryogenic

This

microprocesgauge

flow

ing with an IP65 rated face ideal for use in harsh

in DC filter circuits,

meters for bulk

industrial environments. The dual line bright red LED

power supplies, in-

and

numeric display is easy to read, even at a distance.

dustrial inverters, UPS

transports

micro-bulk appli-

During a high temperature alarm condition the dis-

feature

play flashes and an internal 2 Amp relay circuit is

systems, motor drives, power converters, and solar

cations

inverters, the capacitors are available in nine volt-

the same advanced technology of their liquid flow

activated. Programming of the gauge is quick and

ages spanning 400V-1500V, two tolerances (±5%

measurement products, but are specifically built

easy using the front panel membrane keypad.

and ±10%), two lead lengths (4mm and 8mm),

for low-temperature requirements. The compa-

and with capacitance values spanning 4.7µF to

ny’s cryogenic flow meters are widely known for

The Sensor Connection Info http://powereng.hotims.com RS# 405 www.power-eng.com

Refractometers

(5/16 inch) gun-drilled hole in the cylinder rod to

radiation environments at extra cost.

riez HydroFlow Refractometers are simple yet

measure position rather than a ring magnet or pot

rugged instruments that give users the ability

contact spool. They are offered in ranges from 50

Alliance Sensor Group Info http://powereng.hotims.com RS# 408

to quickly determine the concentration of metal-

to 600mm (2 to 24 inches) full scale with a wide

working coolants and cleaners, heat-treating flu-

variety of on analog I/Os and either connector

Infrared surveillance system

ids, water-based hydraulic fluids and plating baths.

and cable terminations.

The MHP series also includes the MR and ME

GH Infrared Systems offers their latest Spynel model, the Spynel-M. With dimensions of

series for larger cylinders and actuators.

less than 12x20 cm and weight of only 1.8 kg,

Alliance Sensors Group Info http://powereng.hotims.com RS# 407

the Spynel-M is a cost-effective, rugged, and compact solution for wide area surveillance. One single Spynel-M sensor effectively replaces up to

Portable Refractometers require no batteries.

Linear position sensors

16 traditional infrared cameras and is able to per-

he Alliance Sensors Group PG Series LVDT

form 24/7 early human intrusion alerts over a 1.5

linear position sensors are designed and en-

km-diameter area.

They feature a large, easy-to-read scale that is

gineered specifically for valve position sensing

The Spynel-M

available in two ranges: 0-10° Brix and 0-32°

applications for steam turbine control systems in

continuously cap-

Brix. Automatic Temperature Compensating

electric power generation plants.

tures full panoram-

Refractometers provide an ideal solution for sit-

ic, high-resolution

uations in which the temperature of certain fluids

infrared

can affect the refractive index reading of the mix.

every second to

They have a large, easy-to-read scale available in

provide

real-time

two ranges: 0-20° Brix and 0-30° Brix.

security

against

images

Digital

conventional and asymmetrical threats including

Refractometers are also available. They feature an

hardly detectable targets such as UAVs, RHIBs,

easy-to-read LCD readout with a 0-52° Brix range.

or crawling men. Easily transportable, it can be

Eriez HydroFlow Info http://powereng.hotims.com RS# 406

carried in a backpack and quickly deployed on

Extremely

accurate,

hand-held

a light mast or fixed atop a building for superior Alliance Sensors Group’s approach to their

wide area surveillance. While requiring only 8

Position sensors

PG series LVDT design for the power generation

watts of power, Spynel-M can also be operated

lliance Sensors Group expanded its in-cylin-

industry started with the premise that the LVDT

with solar or alternate power supply systems to

der position sensor product line to include the

must be extremely rugged, so these units feature

allow for a remote operation. Unlike radar, the

series

a large diameter housing with a very thick wall

system is completely passive, requires no addi-

linear induc-

and a versatile mounting configuration. A PG se-

tional light source and cannot be jammed. The

tive sensors.

ries LVDT’s 3/8 inch diameter operating rod cap-

intuitive advanced intrusion detection software,

These

MHP

com-

tivates the LVDT’s core so that it can never come

Cyclope, automatically tracks and detects an

pact inductive

out or vibrate loose. This rod is offered with either

unlimited number of targets from any direction at

linear sensors

a rigid coupling or a ball joint coupling that can be

any time of day or night and under any type of

were

de-

helpful in installations where there is a minor mis-

weather conditions. As versatile as it is mobile,

signed to be

alignment with the attachment mechanism on

the system can also be paired with other systems

installed into

the steam valves. PG series LVDTs utilize materials

such as radars and PTZs for data integration and

the rear end-

and manufacturing processes that can be certi-

target identification.

cap of hydraulic cylinders for operation at pres-

fied for use in mild radiation environments found

sures up to 5000psig. Their 1-inch hex aluminum

in boiling water reactor nuclear power plants.

HGH Infrared Systems Info http://powereng.hotims.com RS# 409

or stainless steel housing are ideal for oil and gas

Alliance Sensors Group PG Series LVDTs are

exploration equipment, and mount to the cylinder

available in five full scale ranges from 0-to-3 to

Thermal flow meter

with a standard male o-ring port thread.

0-to-15 inches (75 to 380 mm). Models include

The MHP series sensors are based on a pro-

the PGHD Heavy Duty series LVDT with a 1-1/16

prietary contactless inductive sensing technology

inch body diameter and the PGSD Super Duty se-

FOUNDATION fieldbus digital output communi-

with a short stroke to length ratio. They employ

ries LVDT with a 1-5/16 inch body diameter. Either

cations. This addition signifies the growth of the

a 7 mm diameter probe inserted into an 8 mm

series is available certified for operation in mild

THERMATEL TA2 mass flow technology offering

www.power-eng.com

agnetrol has released of the Thermatel TA2 thermal dispersion mass flow meter with

and

the

MAGNETROL

conductors, with a tool-operated release slot, en-

to extract sta-

con-

abling a high-quality and maintenance-free connec-

tus,

tinued development in

tion between drivers and LED modules. Wire remov-

tics, and other

flow measurement and

al capability (in case of wiring errors or at the end of

information

control solutions. The

module life) is an exclusive feature in this size.

from smart de-

commitment

THERMATEL

TA2

FOUNDATION

diagnos-

with

Surface-mount terminal blocks are especially

vices such as

fieldbus

suited for solid state lighting applications that

field-mounted

offers all of the advan-

often utilize metal-core PCBs, including compact

process trans-

tages of the standard TA2

or miniaturized LED modules and LED ‘bulbs’.

mitters and analyzers. This information can be used

model.

Available in 1-,

by the automation system and/or the asset manage-

Magnetrol Info http://powereng.hotims.com RS# 410

2- and 3-pole

ment system to increase uptime, improve productivi-

configurations,

ty and enhance safety.

group arrange-

HART flow meters protocol option

also

isolated 4-20 mA input channels, and the SNAP-

niversal Flow Monitors, Inc. now offers a HART

possible without

AOA-23-iH output module has two isolated 4-20 mA

protocol option on all of its variable area and

losing any poles. Offering similar functionality as

output channels. Each channel features an integrat-

piston style flowmeters designed to perform in

the field-proven 2060 Series, the 2059 accom-

ed HART modem that allows the channel to commu-

challenging

modates conductors 26-22 AWG with pin spacing

nicate digitally with the HART frequency-shift keying

lubrication

of 3 mm, and is available in tape-and-reel pack-

signal imposed on the 4-20 mA current loop, en-

environments.

aging for automated assembly. The 1-pole variant

abling communication with the target smart device.

These meters

is rated for 3A/600V; the 2- and 3-pole variants

are optimized

are rated for 3A/250V.

Opto 22 Info http://powereng.hotims.com RS# 414

for

Wago Corporation Info http://powereng.hotims.com RS# 412

Chip resistor with Kelvin 4 wire

Diesel mobile generators

specific

lubrication flu-

The SNAP-AIMA-iH analog input module has two

ment

ids. There is an additional option of a mechanical switch to back up the transmitted signal.

he CSSK Series from Stackpole offers a 0612 size chip resistor with Kelvin 4 wire connec-

ohler Power Systems is adding two new mod-

tion. The robust all metal construction withstands

imposed on top of the 4–20 mA standard analog

els to its line of diesel-powered mobile gen-

pulses and environmental stresses with mini-

signal that provides additional digital information

erators. The two new units Kohler’s 145REOZT4

mal resistance shift. The low resistance values

to the controller.

and 175REOZT4 diesel mobile generators offer

down to 0.75 milliohms and the terminations on

HART is a digital communication signal super-

The HART option is offered on all variable area

quiet and reliable operation while delivering de-

the long side of the part handle high currents

vane and piston style flowmeters. These simple

pendable power wherever it’s needed and meet

with relatively low self-induced heating for high

low maintenance meters come in 12 sizes and

all emissions standards.

efficiency.

go up to 2000 PSI pressure for flow ranging up

Kohler Power Systems offers mobile generators

to 500 GPM. They have CSA and CE certifications.

for any application from industrial power to public

Universal Flow Monitors Inc. Info http://powereng.hotims.com RS# 411

events. The company’s 145REOZT4 and 175REOZT4 are EPA-emission certified for non-road use and come equipped with a rugged DOT-certified trailer

Terminal blocks

and durable enclosure. Both units utilize John Deere

ue to their compact size and ease of use,

Tier 4 Final 6.8L engines that help lower operating

WAGO Corp.’s new 2059 SMT PCB terminal

costs with efficient performance and fuel savings.

blocks offer a cost-effective alternative to solder-

Kohler Power Systems Info http://powereng.hotims.com RS# 413

ing leads.

With a height of merely 2.7 mm, the extremely

The CSSK0612 is available in resistance values

compact 2059 reduces the space required for the

Input-Output modules

from 0.75 milliohms to 2 milliohms in 1 percent, 2

connection technology. Designed for the smallest

ndustrial automation manufacturer Opto 22 has

installation spaces, the light color and low profile

percent, and 5 percent tolerances. Pricing varies

released the SNAP-AIMA-iH and SNAP-AOA-23-

with tolerance and resistance and ranges from

of the PCB terminal block substantially reduce on-

iH two-channel analog input and output modules,

$0.25 to $0.40 each in full package quantities.

board LED shadowing. The 2059 Series features

each with HART communications. Both SNAP I/O

a PUSHWIRE connection of solid or pre-bonded

modules use the HART communications protocol

Stackpole Electronics Inc. Info http://powereng.hotims.com RS# 415

www.power-eng.com

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Gas Turbine Inlet Filtration

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Brandenburg is the premier demolition and environmental remediation contractor for power plant decommissioning and retroďŹ tting. Brandenburg services utility companies throughout the U.S. by performing demolition and repurposing projects ranging from selective removal of obsolete equipment to complete closure of power plant facilities.

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SOLVAir Solutions was formed to help customers address the problems of SOX, HCl and other stack emissions, as well as help with the changing EPA regulations. SOLVAir Solutions is the market leader in providing sodium sorbents for use in DSI systems. Access our brochure on our Library page at www.solvair.us

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With 50 yearsĂ of gas turbine OEM expertise,

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Crown Electric

Media Blasting Services

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Fabrication Installation Upgrades & Uprates GSU Change Outs

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Iso Phase Bus

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http://powereng.hotims.com RS#308

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NuScale Power has attained the Triple Crown for Nuclear Plant Safetyâ&#x201E;˘. With NO operator action, NO AC or DC power, and NO added water, the NuScale Power Moduleâ&#x201E;˘ will achieve safe, self-cooled shutdown, and maintain it indeďŹ nitely.

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Sho-Me Technologies, a wholly owned subsidiary of Sho-Me Power, provides fber optic broadband communication services to rural Missouri. Headquartered in Marshfeld, operations personnel are strategically located at 3 crew facilities to minimize emergency response times. Facilities include Marshfeld, Cuba and Willow Springs, Missouri. The cooperative has 150 employees, operating and maintaining over 1,800 miles of electric transmission line, operated at voltages from 69 kV to 345 kV, connecting 22 transmission and 133 distribution substations throughout south central Missouri. In 2014, the G&T had consolidated annual operating revenues of $207,058,927, total operating expenses of $201,091,540 and a total net utility plant of $265,717,000. Thirty-seven of the cooperatives’ 150 employees are assigned to its subsidiary Sho-Me Technologies which operates over 5,000 miles of fber optic communication equipment and provides services to cell towers, educational institutions, medical facilities, government, and fnancial institutions in Missouri. Candidates should have a minimum of ten years of electric utility experience, preferably within the rural electric program and at least fve years senior management experience. Candidates must have broad electric utility experience encompassing the areas of operations, fnance, engineering, technology, marketing, power supply, strategic planning, union relations, member communications and board relations. Excellent communication skills, proven leadership ability and a strong commitment to cooperative principles is required. A bachelor’s degree in an appropriate feld is required. Interested candidates should include a resume, cover letter and a minimum of three (3) professional references or letters forwarded to: Andereck, Evans, Widger, Johnson & Lewis, LLC, ATTN: Rodric A. Widger, 3816 South Greystone Court, Suite B, Springfeld, Missouri, 65804, 417-864-6401. Electronic copies should be forwarded to rwidger@lawofcemo.com. Applications will be accepted from September 1 through October 1, 2015. All inquiries and applications are confdential. Sho-Me Power Electric Cooperative is an equal opportunity provider and employer. All qualifed applicants will receive consideration for employment without regard to race, color, religion, sex, sexual orientation, gender identity, national origin, disability status, protected veteran status, or any other characteristic protected by law. EOE AA M/F/Vet/Disability

For info. http://powereng.hotims.com RS# 450

Classified advertising ContaCt Jenna Hall: 918-832-9249, JennaH@pennwell.Com

The Board of Directors of Sho-Me Power Electric Cooperative is seeking qualifed candidates for the position of General Manager. The General Manager reports to a ninemember Board of Directors that sets policy and approves electric rates for both members and non-members of Sho-Me Power. Sho-Me Power Electric Cooperative is a generation and transmission electric cooperative owned by nine distribution cooperatives who serve over 200,000 retail customers in southern Missouri. Sho-Me’s power requirements are supplied by Associated Electric Cooperative, Inc. (AECI), created by Sho-Me and fve other G&T cooperatives in 1961.

CLASSIFIEDS |

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| CLASSIFIEDS Classified advertising ContaCt Jenna Hall: 918-832-9249, JennaH@pennwell.Com

WE BUY

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For info. http://powereng.hotims.com RS# 453

POWER PROFESSIONALS Opportunities in Operations and Maintenance, Project Engineering and Project Management. Business and Project Development. First-line Supervision to Executive Level Positions. Employer pays fee. Send resumes to:

For info. http://powereng.hotims.com RS# 451 GEORGE H. BODMAN, INC. Chemical cleaning advisory services for boilers and balance of plant systems

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For info. http://powereng.hotims.com RS# 454

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For info. http://powereng.hotims.com RS# 455

For info. http://powereng.hotims.com RS# 458

For Classified Advertising Rates & Information Contact Jenna Hall Phone - 918-832-9249, Jennah@pennwell.com For info. http://powereng.hotims.com RS# 460 CONDENSER & HEAT EXCHANGER TOOLS CLEANERS, PLUGS, BRUSHES

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e-mail: sales@johnrrobinsoninc.com

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For info. http://powereng.hotims.com RS# 456

Quality and Service Since 1908

Ring Granulators, Reversible Hammermills, Double Roll Crushers, Frozen Coal Crackers for crushing coal, limstone and slag. 1319 Macklind Ave., St. Louis, MO 63110 Ph: (314) 781-6100 / Fax: (314) 781-9209 www.ampulverizer.com / E-Mail: sales@ampulverizer.com

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For info. http://powereng.hotims.com RS# 461

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For info. http://powereng.hotims.com RS# 457

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For info. http://powereng.hotims.com RS# 462

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INDEX RS# COMPANY

PG#

3 Brand Energy and 5 Infrastructure Services www.beis.com

6 Buckman

RS# COMPANY

PG#

Rentech Boiler Systems, Inc. DIGITAL EDITION-COVER www.rentechboilers.com

9 Roxul Inc

www.roxul.com

14 Cleaver-Brooks Inc

www.cleaverbrooks.com

4 Haldor Topsoe Inc

www.topsoe.com

2 Indeck Power Equipment 3 7

www.sealeze.com

8 Structural Integrity Associates

www.indeck-keystone.com

www.structint.com/power-eng

Lapeyre Stair

Sulzer Management Ltd

DIGITAL EDITION-BELLY BAND

www.lapeyrestair.com

5 Magnetrol International 9 www.magnetrol.com

12 Sealeze, A Unit of Jason, Inc

Mitsubishi Power C2 Systems Americas Inc www.mhpowersystems.com

11 PennWell Corporation 36 www.power-eng.com/webcasts

13 POWER-GEN International

www.power-gen.com

15 ProEnergy Services LLC C4 www.proenergyservices.com

www.sulzer.com

10 Sulzer Turbo Services

www.sulzer.com

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SALES OFFICE 1421 S. Sheridan Rd., Tulsa, OK 74112 Phone: 918-835-3161, Fax: 918-831-9834 e-mail: pe@pennwell.com Sr. Vice President North American Power Group Richard Baker Reprints Foster Printing Servive 4295 Ohio Street, Michigan City, IN 46360 Phone: 866-879-9144 e-mail: pennwellreprint@fosterprinting.com National Marketing Consultant Rick Huntzicker Palladian Professional Park 3225 Shallowford Rd., Suite 800 Marietta, GA 30062 Phone: 770-578-2688, Fax: 770-578-2690 e-mail: rickh@pennwell.com AL, AR, DC, FL, GA, KS, KY, LA, MD, MO, MS, NC, SC, TN, TX, VA, WV Regional Marketing Consultant Dan Idoine 806 Park Village Drive, Louisville, OH 44641 Phone: 330-875-6581, Fax: 330-875-4462 e-mail: dani@pennwell.com CT, DE, IL, IN, MA, ME, MI, NH, NJ, NY, OH, PA, RI, VT, Quebec, New Brunswick, Nova Scotia, Newfoundland, Ontario Regional Marketing Consultant Natasha Cole 1455 West Loop South, Suite 400 Houston, Texas 77027 Phone: 713.499.6311; Fax: 713.963.6284 e-mail: natashac@pennwell.com AK, AZ,CA,CO,HI,IA,MN,MT,ND,NE,NM,NV, OK,OR,SD,UT,WA,WI,WY,AB,BC,SK, Manitoba, Northwest Territory, Yukon Territory Regional Brand Manager Kelly Balaskovits 1421 S. Sheridan Rd., Tulsa, OK 74112 Phone: 918-831-9129; Fax: 918.831.9834 e-mail: kellyb@pennwell.com AK, AZ,CA,CO,HI,IA,MN,MT,ND,NE,NM,NV, OK,OR,SD,UT,WA,WI,WY,AB,BC,SK, Manitoba, Northwest Territory, Yukon Territory International Sales Mgr Tom Marler The Water Tower Gunpowder Mills Powdermill Lane Waltham Abbey, Essex EN9 1BN United Kingdom Phone: +44 1992 656 608, Fax: +44 1992 656 700 email: tomm@pennwell.com Belgium, Czech Republic, Denmark, Finland, France, Germany, Hungary, Norway, Poland, Portugal, Slovenia, Spain, Slovakia, Sweden International Sales Mgr Roy Morris The Water Tower Gunpowder Mills Powdermill Lane Waltham Abbey, Essex EN9 1BN United Kingdom Phone: +44 1992 656 613, Fax: +44 1992 656 700 email: rmorris@pennwell.com UK, Austria, Africa, Holland, India, Italy, Ireland, Israel, Russia, Australia & New Zealand, Singapore, Scotland, Switzerland, Turkey, Greece, UAE/SAUDI and Iran Classifieds/Literature Showcase Account Executive Jenna Hall 1421 S. Sheridan Rd., Tulsa, OK 74112 Phone: 918-832-9249, Fax: 918-831-9834 email: jennah@pennwell.com

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When you need BIG POWER, total integration generates bigger and better results. No matter the business — reﬁnery, utility, manufacturing or petrochemical — if you are in an industry that demands big power, you’ll want to check out the complete range of boiler systems from Cleaver-Brooks. For more than 80 years, we have set the industry standard in the design and production of boiler systems that continually maximize efﬁciency and deliver uncompromising reliability and the lowest possible emissions. Our total integration is that every component — from gas inlet to stack outlet — is designed, engineered and manufactured by just one company.

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