June 2014 by Energy-Tech Magazine

Cooling Tower Cleaning 6 • Gas Inlet Cooling 10 • ASME: RAM Programs 20

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JUNE 2014

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FEAtUrEs

By Brad Buecker, Energy-Tech contributor

Editorial Board (editorial@WoodwardBizMedia.com) Kris Brandt – Rockwell Automation Bill Moore – Director, Technical Service, National Electric Coil Ram Madugula – Executive Vice President, Power Engineers Collaborative, LLC Kuda Mutama – Engineering Manager, TS Power Plant Editorial views expressed within do not necessarily reflect those of Energy-Tech magazine or WoodwardBizMedia. Advertising Sales Executives Tim Koehler – tkoehler@WoodwardBizMedia.com Juli Hoppensteadt – jhopp@WoodwardBizMedia.com Joan Gross – jgross@WoodwardBizMedia.com

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June 2014

Regulations Compliance

Boiler tuning for MATS compliance By Jim Sutton and Tony Criswell, Alstom

Mr. Megawatt

Looking past the usual suspects By Frank Todd, True North Consulting

Turbine Tech

The importance of pure, dry hydrogen cooling gas By John Speranza, Proton OnSite

AsME FEAtUrE

Creative/Production Manager Hobie Wood – hwood@WoodwardBizMedia.com Graphic Artist Valerie Vorwald – vvorwald@WoodwardBizMedia.com Address Correction Postmaster: Send address correction to: Energy-Tech, P.O. Box 388, Dubuque, IA 52004-0388 Subscription Information Energy-Tech is mailed free to all qualified requesters. To subscribe, go to www.energy-tech.com or contact Linda Flannery at circulation@WoodwardBizMedia.com Media Information For media kits, contact Energy-Tech at 800.977.0474, www.energy-tech.com or sales@WoodwardBizMedia.com. Editorial Submission Send press releases to: Editorial Dept., Energy-Tech, P.O. Box 388, Dubuque, IA 52004-0388 Ph 563.588.3857 • Fax 563.588.3848 email: editorial@WoodwardBizMedia.com. Advertising Submission Send advertising submissions to: Energy-Tech, 801 Bluff Street, Dubuque, Iowa 52001 E-mail: ETart@WoodwardBizMedia.com.

Hybrid systems for gas turbine inlet cooling By Marcus Bastianen, P.E., Everest Sciences Inc.

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Ensuring cooling tower cleanliness in a more stringent regulatory environment

Taking on Goliath: Implementing an effective RAM program for an existing power plant By Brian Wodka, RMF Engineering Inc.

iNdUstrY NotEs

4 30 31

Editor’s Note and Calendar Advertisers’ Index Energy Showcase

oN tHE WEB Energy-Tech’s library of white papers is free and covers every aspect of the power-gen plant. Check out our latest paper, DCS Versus PLC: A User’s Guide To Selecting The Most Effective Control Platform For Your Application, by Revere Control Systems. Find it at energy-tech.contentshelf.com. Cover photo contributed by Alstom.

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Editor’s Note

Bridging the gap with ASME This month’s letter from the ASME committee chairman grabbed my attention. It is one of the most direct arguments I’ve heard in a while about the need for power engineers to adapt to the changing landscape of power generation. The same old, same old won’t cut it anymore, RAM Chair Brian Wodka asserts, and the industry needs the experience and expertise of its older engineers to help in the transition, “to bridge the gap between what the populous wants, and what can practically be done.” It’s a great letter – I hope you take time to read it on page 21. Reading it also reminded me that the 2014 ASME Power Conference is only a month away. This year’s conference will be held July 28-31 in Baltimore, Md. Titled, Plant Optimization and Knowledge Transfer: Getting The Most Out of Your Megawatts, the conference brings together some of the best minds in the power industry for four days of lecture, discussion and problem solving. If you’re arriving a day or two early in Baltimore, there’s still time to register for one or two of the four workshops that are being offered on Sunday and Monday, July 27-28. The workshop class sizes are small and a great opportunity to hammer out questions from knowledgeable instructors on topics such as condensers, pumps and turbines and generators. I’m already thinking about which technical tracks I want to attend this year. There are so many options, and the conference goes so quickly, that I try to have a good idea where I’ll be spending my time before the plane lands. I’m particularly looking forward to the student paper competition, which is new this year. We will be publishing the best paper from the student track in a 2015 digital issue of Energy-Tech, so I’m excited to see the presentations. My favorite part of the conference every year, though, is catching up with all of the Energy-Tech readers who stop by our booth in the exhibit hall. I’ve had so many great conversations, which have led to excellent articles and ideas for the magazine. If you’re attending the conference, please be sure to stop and say hello, and if you want more information about the conference, visit www.asmeconferences.org/POWER2014. I hope we see you in July. Until then, thanks for reading.

CALENDAR June 11-13, 2014 2014 Vibration Institute Training Conference San Antonio, Texas www.vi-institute.org June 11-13, 2014 3rd Natural Gas Vehicles USA Conference & Exhibition Houston, Texas www.ngvevent.com July 21-25, 2014 Rotor Dynamics and Modeling Syria, Va. www.vi-institute.org July 28-31, 2014 ASME 2014 Power Conference Baltimore, Md. www.asmeconferences.org/power2014 Aug. 19-22, 2014 Balancing of Rotating Machinery Houston, Texas www.vi-institute.org Sept. 16-19, 2014 Machinery Vibration Analysis Salem, Mass. www.vi-institute.org Nov. 3-4, 2014 CCGT 2014: O&M and Lifecycle Management for CCGT Power Plants Houston, Texas www.tacook.com/ccgt-usa Nov. 11-14, 2014 Advanced Vibration Control Syria, Va. www.vi-institute.org

Submit your events by emailing editorial@woodwardbizmedia.com.

Andrea Hauser

ENERGY-TECH.com

June 2014

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Ensuring cooling tower cleanliness in a more stringent regulatory environment By Brad Buecker, Energy-Tech contributor

The shale gas revolution has led to planning and installation of many new combined-cycle power plants. For a long time none of the proposals I have seen called for oncethrough condenser cooling, due to pending 316a and 316 b regulations that respectively address thermal discharge and protection of aquatic creatures at cooling water intake structures. The majority of new projects are specified with wet cooling towers or some version thereof, while others require air-cooled condensers. An obvious, but challenging, aspect of cooling tower operation is keeping the tower, condenser and other system components free of microbiological fouling, scaling and solids deposition. Even with fresh water as makeup from a lake or river, cooling system chemistry control requires diligence and good planning. But now the industry is seeing a rapidly growing number of plants that are required to use less-thanpristine makeup sources, and most notably wastewater discharge plant effluent, commonly known as gray water. The first difficulty with such waters is that they provide nutrients for microbiological fouling. By far, this issue causes the most problems in cooling systems. Cooling systems provide an ideal environment, warm and wet, for microbes. Bacteria will grow in condensers and cooling tower fill, fungi on and in cooling tower wood, and algae on wetted cooling tower components exposed to sunlight. Biocide treatment is absolutely essential to maintain cooling system performance and integrity. Bacteria are separated into the following three categories: • Aerobic: Utilize oxygen in the metabolic process. • Anaerobic: Live in oxygen-free environments and use other sources, i.e., sulfates, nitrates or other donors for their energy supply. • Facultative: Can live in aerobic or anaerobic environments. A problem with microbes, particularly bacteria, is that once they settle on a surface the organisms secrete a polysaccharide layer for protection. This film then will collect silt from the water, growing even thicker and further reducing heat transfer. Even though the bacteria at the surface might be aerobic, the secretion layer allows anaerobic bacteria underneath to flourish. These bugs can then generate acids and other harmful compounds that directly attack the metal. Microbial deposits also establish concentration cells, where the lack of oxygen underneath the deposit causes the locations to become anodic to other areas of exposed metal.

ENERGY-TECH.com

Figure 1. Fouled cooling tower film fill. Source: Reference 1

Pitting is often a result, which can cause tube failure well before the expected lifetime of the material. Fungi will attack cooling tower wood in an irreversible manner, which can eventually lead to structural failure. Algae will foul cooling tower spray decks, potentially leading to reduced performance and unsafe working locations. The core of most microbiological treatment programs is feed of an oxidizing biocide to kill organisms before they can settle on condenser tube walls, cooling tower fill and other locations. Chlorine was the workhorse for many years, and when gaseous chlorine is added to water the following reaction occurs: Cl2 + H2O ↔ HOCl + HCl HOCl, hypochlorous acid, is the killing agent. The functionality and killing power of this compound is greatly affected by pH due to the equilibrium nature of HOCl in water.

June 2014

FEATURES Table 1 – Non-Oxidizing Biocides Chemical 2,2,-dibromo-3-nitrilopropionamide (DBNPA) Glutaraldehyde Isothiozoline Quaternary amines

Advantages

Disadvantages

Fast acting, effective against bacteria, degrades quickly to non-hazardous byproducts.

Expensive, degrades quickly above pH 9, not very effective against fungi and algae.

Effective at high pH, effective against bacteria.

Degraded by oxidizing biocides.

Effective against bacteria and fungi. Works well with oxidizing biocides. Active over a wide pH range.

Skin sensitizer.

Effective against all organisms depending upon functional groups attached. Active over a wide pH range.

Can cause foaming. Careful handling required.

Table 1 – Non-oxidizing biocides

HOCl ↔ H+ + OClOCl- is a much weaker biocide than HOCl, probably due to the fact that the charge on the OCl- ion does not allow it to penetrate cell walls. The killing efficiency of chlorine dramatically declines as the pH goes above 7.5. Thus, for the common alkaline scale/corrosion treatment programs, chlorine chemistry might not be efficient. Chlorine demand is further affected by ammonia or amines in the water, which react irreversibly to form the much less potent chloramines. Due to safety concerns, liquid bleach (NaOCl) feed has replaced gaseous chlorine at many facilities. A popular alternative is bromine chemistry, where a chlorine oxidizer and a bromide salt, typically sodium bromide (NaBr), are blended in a makeup water stream and injected into the cooling water. The chemistry produces hypobromous acid (HOBr), which has similar killing powers to HOCl, but functions more effectively at alkaline pH. Chlorine dioxide (ClO2) is becoming more popular for several reasons. Its killing power is not affected by pH, the chemical does not react with ammonia, and it does not form halogenated organic compounds. Also, chlorine dioxide is more effective in attacking established bio-deposits. ClO2 is unstable and must be generated on-site. In the past, a common method was reaction of sodium chlorite (NaClO2) and chlorine in a slipstream fed to the cooling water.

NaClO3 + 1/2 H2O2 + 1/2 H2SO4 → ClO2 + 1/2 O2 + 1/2 Na2SO4 + H2O Note that sodium chlorate (NaClO3) is the core chemical Figure 2. HOCl vs. HOBr effectiveness rather than sodium chlorite. A method to help control microbes is a supplemental feed of a non-oxidizing biocide. Typically, feed is needed on a temporary but regular basis, perhaps once per week. Table 3 outlines some of the properties of the most common non-oxidizers.

Restoration of

Gas Turbine

Bearings

2NaClO2 + Cl2 → 2ClO2 + 2NaCl However, this technique required storage of large quantities of hazardous chemicals and was several times more expensive than bleach, or even bromine treatment. Improved technology is now available, with one design based on the following chemistry.

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FEATURES Table 2 – Snapshot Analysis of A Midwestern Lake Major Cations (as species)

Major Anions (as species)

Other

Calcium – 60 ppm

Chloride – 32 ppm

Silica – 2ppm

Magnesium – 12 ppm

Sulfate – 77 ppm

Iron – 0.1 ppm

Sodium – 32 ppm

Alkalinity – 163 ppm

Manganese – 0.1 ppm

Potassium – 7 ppm

Nitrate – 0.5 ppm

Turbidity – 5 NTU

Table 2 – Snapshot analysis of a Midwestern lake

Careful evaluation of the microbial species in the cooling water is necessary to determine the most effective biocides. None of these chemicals should be used or even tested without approval from the appropriate regulating agency. They must fit in with the Figures 3a and 3b. Two plant’s National Pollutant Discharge common phosphonates, Elimination System (NPDES) guide1-hydroxyethylidene-1,1-dilines. phosphonic acid (HEDP), top, and 2-phosphono-buAs with all chemicals, safety is an tane-1,2,4-tricarboxylic acid absolutely critical issue when han(PBTC), bottom. dling the non-oxidizers. Adherence to all handling guidelines and use of proper personal protective equipment is a must. Many of these chemicals will attack human cells, as well as those of microbes.

Scale control In the “good old days” of cooling tower operation, a very common treatment program consisted of a first step of sulfuric acid addition to the makeup to remove bicarbonate alkalinity. H+ + HCO3 - → CO2↑ + H2O A typical pH range of the circulating water was 6.5 to 7.0 or thereabouts, which minimized scale formation. Corrosion protection was provided by treatment with sodium chromate, which caused steel surface layers to form a pseudo-stainless steel layer that protected the metal. However, chromate treatment in all open-recirculating and most other cooling water systems has been banned for years due to the toxicity of hexavalent chromium (Cr+6). The popular replacement has been alkaline-based treatment, primarily relying on inorganic and organic phosphates (phosphonates), with a supplemental polymer to sequester and modify non-carbonate scaleformers, and perhaps a low dosage of a zinc salt. When properly applied, the treatment minimizes corrosion due to several factors, including operation at an alkaline pH. Also, phosphonates function as crystal modifiers and alter crystal structures to reduce the crystals’ adhesiveness to con-

ENERGY-TECH.com

Figure 4. A state-based illustration of phosphorus-impaired waters. Source: USGS

denser tubes and other surfaces. An organic polymer is typically included to prevent calcium phosphate scale formation. Evolving environmental concerns are now casting a shadow on this treatment method at an increasing number of facilities. Phosphate is a prime nutrient for plant growth and many receiving bodies of water have become “phosphate-impaired,” where they suffer from extensive and toxic algae blooms. Much research has gone into and continues for all-polymer treatment programs. Depending on the water constituents, these polymers might have a variety of active groups, which principally act by crystal modification and dispersion to minimize scaling. When choosing a cooling water treatment program, modeling software can be very beneficial. French Creek Software is a leader in this technology, and many of the major water treatment chemical vendors utilize the software for their programs.

Makeup water issues We have briefly examined the issue of cooling tower makeup, particularly as it applies to the increasing use of gray water as the source. Let us examine this issue in a bit more detail. In the past, most cooling towers have been supplied from fresh water sources, and often lakes or reservoirs. A snapshot analysis from a Midwestern lake that supplies cooling water to a large power plant shows a reasonable general chemistry. Ammonia and phosphorus concentrations in the water are negligible. Gray water, on the other hand, might contain double-digit quantities of ammonia, phosphate and much higher suspended solids. Influences they might have upon operation include: • Ammonia and phosphate serve as nutrients for microbiological growth within the cooling system. • If the plant has relied on chlorine or bleach feed for microbiological control, the ammonia will upset the treatment plan and operation.

June 2014

FEATURES • The external phosphate loading can seriously impact the cooling tower treatment program and induce scale formation. • The greater suspended solids might increase fouling. • The cooling tower blowdown might violate discharge limits for phosphate, ammonia or other compounds. Plant personnel and consulting engineers increasingly have to consider installation of makeup and discharge treatment systems to mitigate the impurities introduced by recycled or otherwise non-pristine makeup water supplies. Figure 5. Cooling water treatment polymer structures showing active groups. Source: Reference 1 For example, clarification with feed of an iron or • aluminum coagulant might reduce phosphate via precipitation and removal with the • • clarifier sludge. At one current project in which the author has become involved, SELL • RENT• LEASE • ammonia is removed from makeup by a media-based bioreactor unit. Membrane - 24 / 7 • EMERGENCY SERVICE bioreactors are another technology to accomplish ammonia removal, as are ammonia • strippers, which might be based either on pH or temperature adjustment to remove • ammonia. Cooling tower blowdown treatment scenarios might include membranes, • • ion exchange and evaporator/crystallizer technologies to reduce impurities in the • discharge, or even to achieve zero liquid discharge. In all cases, rigorous bench-top • IMMEDIATE DELIVERY testing and, whenever possible, pilot testing are necessary to ensure that the desired • treatment technology will suffice. Too many systems have been installed based on the- • • oretical validity that then failed in direct application. ~ 10HP TO 250,000#/hr

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Reference 1. R. Post and B. Buecker, “Power Plant Cooling Water Fundamentals”; the pre-conference seminar for the 33rd Annual Electric Utility Chemistry Workshop June 13-15, 2013, Champaign, Illinois. Brad Buecker is a process specialist in the Environmental Services group of Kiewit Power Engineers, Lenexa, Kan. The group provides consulting and engineering for industrial water/ wastewater projects. He has more than 32 years of experience in, or affiliated with, the power and CPI industries, much of it in chemistry, water treatment, air quality control and results engineering positions with City Water, Light & Power in Springfield, Ill., and Kansas City Power & Light Company’s La Cygne, Kan., station. Buecker has a bachelor’s degree in chemistry from Iowa State University, with additional course work in energy and materials balances, advanced inorganic chemistry and fluid mechanics. He has written many articles and three books on steam generation topics. He is a member of the ACS, AIChE, ASME, CTI and NACE. He also is a member of the ASME Research Committee on Power Plant & Environmental Chemistry and the program planning committee for the Electric Utility Chemistry Workshop. You may contact him by e-mailing editorial@ woodwardbizmedia.com.

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FEATURES

Hybrid systems for gas turbine inlet cooling By Marcus Bastianen, P.E., Everest Sciences Inc.

With natural gas prices at near-historical lows, and regulatory pressure driving plant owners to generate “greener” power, the need for efficiency has never been greater. Turbine inlet cooling using hybrid systems can increase power output on hot days and lower operational costs. Gas turbines are mass flow machines with a volumetrically constrained intake. The density of the air drawn into the turbine intake directly affects the power output of a turbine and the amount of electricity that it can generate. Air density is primarily determined by temperature and altitude. The higher the altitude or ambient air temperature, the lower the air density. Turbine inlet cooling directly increases inlet air density and therefore the power generated by the gas turbine. This article, and its accompanying webinar on June 5, will examine the challenges that plant owners using gas turbines face at high altitudes and during changing climate conditions. The webinar will further discuss the solutions available, including additional generation, traditional inlet cooling methods using direct evaporative or mechanical chilling, and Everest Sciences Hybrid systems that use an indirect evaporative process combined with other technology.

benefits base load, peaking and island power applications where small- to medium-size turbines often operate in simple cycle or co-generation. Traditional turbine inlet cooling methods currently available include direct evaporative techniques such as wetted media and fogging systems. An alternative to direct evaporative methods is indirect evaporative cooling; a water-based heat extraction proTurbine inlet cooling cess that works well with hybrid Turbine inlet cooling continues designs. To gain a better underDon’t miss Energy-Tech’s June 5 to prove an economical power standing of the advantage inlet webinar on gas turbines with Brad augmentation proposition to cooling provides for power generincrease the output of an Irwin, from Everest Sciences. Register ation applications, one should have engine as ambient air a general understanding of how the at www.energy-tech.com temperatures rises and cooling mechanisms work. inlet air density falls. Direct evaporative cooling is an The intake of a gas turbine is volumetrically adiabatic (isocaloric) humidification process where no heat is limited. Improving the density of the inlet transferred to or from the working fluid. The process cools the air to the turbine compressor section surrounding air through the vaporization of water. The added allows for greater mass flow to the water vapor increases the latent heat and the relative humidity, engine, creating more power but retains total heat at a constant value. Although the air “feels” output while improving cooler, the total air enthalpy remains unchanged. the engine efficiency/ However, this process does increase the density of the air heat rate. Inlet cooling ingested by the compressor section of the gas turbine; consequently, increasing the mass flow to the machine. Two common Failure to properly ways to use direct evaporative cooling are through wetted media ground rotating and fogging.

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June 2014

FEATURES

Figure 2

Wetted media This method requires the distribution of a controlled volume of water over fluted media, where the air and water can interact. The inlet air is exposed to a fine water curtain promoting evaporation of water into the air stream. The evaporation process cools the inlet air dry bulb temperature up to as much as 85 percent of the difference between the ambient air dry-bulb and wet-bulb temperatures, often referred to as the wet bulb depression. Regardless of the media supplier recommendations, some water vapor is added to the inlet air stream going to the gas turbine; therefore users should also consult with the turbine OEM guidelines which might be more stringent about water quality used in the specific application. Fogging Fogging techniques make use of a high pressure spray through atomizing nozzles. The droplets of varying sizes introduced into the turbine inlet airstream evaporate and can theoretically cool the air to its saturation temperature, or dew point (Turbine Inlet Cooling Association â&#x20AC;&#x201C; Technology Overview). As water is directly evaporated in the intake air stream, it must be clear of any mineral salts and other impurities. Therefore, the water used in fogging systems is generally de-mineralized, which can be produced by reverse osmosis among other methods. Indirect evaporative cooling As an alternative to direct evaporative methods, indirect evaporative cooling uses cross-flow heat exchangers to cool the turbine inlet air. Water is evaporated in a secondary air stream

Figure 3

that is then used to extract heat from the primary turbine inlet air stream via heat exchangers. This heat transfer means that turbine inlet air enthalpy is lowered as energy is actually removed from the turbine inlet air to the secondary air flow, allowing for denser inlet air than direct evaporative techniques alone. Inlet air to the turbine can be cooled by up to 95 percent of the wet bulb depression. The primary air passing to the turbine does not contact with the secondary cooling air stream or the moisture it contains, therefore, the air is not contaminated with salts, min-

June 2014 ENERGY-TECH.com

FEATURES

Figure 7

Figure 4

Figure 5

Figure 6

erals, or water vapor sometimes found with direct evaporative techniques. Water quality requirements for indirect evaporative cooling are less stringent than direct evaporative techniques. In addition, the threat of cooling water impingement with the compressor section of the gas turbine is removed.

ENERGY-TECH.com

Hybrid systems Another method of gas turbine inlet cooling is to use a hybrid system, which provides a fine grained control over inlet air temperature. The term “hybrid” comes from combining various inlet cooling technologies. An example of a multistage hybrid system includes a first stage of indirect evaporative cooling followed by a second stage of direct evaporative cooling. This hybrid combination provides air that leaves the first stage at a lower than ambient dry bulb and wet bulb, allowing the second stage evaporative cooler to further reduce the air temperature close to the indirect stage wet bulb temperature, which is several degrees cooler than the ambient wet bulb temperature. The combined cooling results in intake air temperatures 5°F to 20°F (3°C to 11°C) cooler than traditional evaporative cooling alone and therefore, provides more dense air to the turbine and results in greater electrical output power. Case study: Large California medical center With Everest Sciences’ experience in air handling solutions – including indirect evaporative and hybrid systems – the company has worked with a wide range of customers to solve hot day gas turbine nuisances. One example is a large U.S. government medical center in the San Diego area produces its own power using a gas turbine. Using Everest Sciences’ CleanChill™ allows the customer to efficiently target specific inlet air temperatures, using an integrated air handling package that includes multistaged filtration and moisture separation around the chilling design. The medical center shares an industry-wide commitment to economically sound, environmentally friendly solutions for power generation. Since they have already implemented a co-generation system to improve energy efficiency, the next step – air cooling for our filterhouse – made perfect sense. With the new system in place, they can ensure that the turbine is operating at peak efficiency all the time. ~ Marcus Bastianen P.E. is vice president of Sales and Operations for Everest Sciences Corp. Prior to joining Everest Sciences, Bastianen worked in the application, design, manufacturing and management of petrochemical and energy projects in the oil and gas industry. He graduated with a bachelor’s degree in Civil Engineering from the University of Wisconsin and an MBA from the University of Tulsa. You may contact him by emailing editorial@woodwardbizmedia.com.

June 2014

REGULATIONS COMPLIANCE

Boiler tuning for MATS compliance By Jim Sutton and Tony Criswell, Alstom

Achieving efficient combustion and electric power generation with minimized emissions requires periodic burner inspections and boiler tuning. Equipment operators have performed boiler tuning since the start of electric generation, but recent changes in U.S. regulations have increased the focus on conducting wellrun periodic burner inspections and boiler combustion tuning campaigns. This allows coal- and oil-fired utility boiler operators to minimize the emission of hazardous organic substances while efficiently producing electricity.

The issue The Clean Air Act (CAA) and amendments charged the U.S. Environmental Protection Agency (EPA) with the responsibility of setting regulations for SOX, NOX and Hazardous Air Pollutant (HAP) emissions from utility power plants. The EPA, in turn, issued binding regulations that created a marketplace-based reduction system. This system brought about significant reduction in SOX and NOX emissions. Until recently, regulations concerning the HAPs, (mercury, arsenic, heavy metals, as well as dioxins and furans) have only been under study. The EPA completed its obligation under the CAA by issuing a final rule on these “other” emissions, which was published in the Federal Register on Feb. 16, 2012, as MATS, an acronym for Mercury and Air Toxics Standards. The legislation sets air pollution limits for HAP emissions by coal- and oil-fired electric generating units (EGU) with a capacity of 25MW or greater. Each EGU must comply with the provisions of MATS within 3 years, plus 60 days of publication in the register, setting April 16, 2015, as the compliance date. There is a provision for an extra year, at the discretion of the regulators. The MATS rule covers stack monitoring of mercury, particulates, control of organic HAP emissions through work practice standards, as well as startup and shut-down work practice standards. The organic work practices are the focus of this article. The overall intent of the regulation is to minimize HAP emissions by ensuring that the burners are in good working order, the controls are working properly and the system has been correctly tuned. If these activities are conducted carefully by skilled personnel, CO emissions will be minimized consistent with industry and OEM practice. CO is an important indicator, since research has shown that systems that have high CO emissions might have higher hazardous organics emissions. Initial compliance with the tuning must occur within 180 days of the compliance date of the rule, setting Oct. 13, 2015, as the date required for initial tune-up (Oct. 13, 2016, if a neural net is in operation). Additionally, the first tune-up might be delayed until the next outage if certain requirements are fulfilled.

Figure 1. Tangential fired boiler

Requirements of the tune-up work practice standard The Work Practice Standard Rule outlines nine specific requirements for tune-ups: 1. Inspect the burner and combustion controls at least once every 36 months. There is a provision in the law for a 48 month period if a neural net optimizer is employed (see sidebar). Each EGU must clean Figure 2. Coal and air injection or replace any out of tolerance components. Burner or combustion control components needing replacement that affect the ability to optimize NOX and CO must be installed within 3 calendar months after the burner inspection. 2. Inspect the flame pattern. Each EGU must make any adjustments to the burner necessary to optimize the flame pattern. The adjustment should be consistent with the manufacturer’s specifications, if available, or in accordance with best combustion engineering practice. 3. Observe damper operations. As applicable, observe the damper operations as a function of mill and/or cyclone loadings, cyclone and pulverizer coal feeder loadings, or other pulverizer and coal mill performance parameters, making adjustments and effecting repair to dampers, controls, mills, pulverizers, cyclones and sensors.

June 2014 ENERGY-TECH.com

REGULATIONS COMPLIANCE Neural networks All coal-fired boilers benefit from optimized controls. As a boiler Original Equipment Manufacturer (OEM), Alstom has provided control and safety logic for hundreds systems, as well as field service support to address a variety of operational and performance issues as customers have changed fuels and optimized operation for lower emissions. With time, we have seen the technology for control of air, fuel and boiler load improve. Specifically, we have seen great benefit in upgrading traditional PID controllers with effective and easy to use neural net based combustion optimization systems (COS) that continually monitor plant conditions and evaluate changes against plant targets. This solution cost effectively improves heat rate, reduces NOX and improves CO control. The benefit of neural net optimizers also is recognized by the EPA, which allows EGU’s longer intervals between tune-ups. Computerized neural networks are mathematical models inspired by animals’ central nervous systems. They relate system inputs to system outputs through interconnected “neurons” with assigned weights. These weights are computed based on historical data under various operating conditions. The model can now calculate a predicted emission for a set of input conditions. Alternatively, the model can be used to identify the best combination of operating inputs that will produce the best boiler efficiency with low NOX and CO emissions. Once the optimal settings are determined, they can be relayed to the plant distributed control system (DCS) for implementation. In this way, the plant controls can be continuously adjusted to ensure NOX and CO are minimized. Implementation is typically done in three steps: • Initial setup and establish link to the DCS. Best performed in outage, 2-3 weeks • Data gathering and limited operation with constraints, 6-8 weeks of data gathering • Operation with robust model. Achieved by tuning and retraining neural net model, 3 weeks Since the COS systems works with existing sensors and control systems, it is a relatively low capitol cost investment and can be expected to generate a 0.4 percent improvement in heat rate, with some reduction in NOX and CO.

Figure 3. Coal compartment assembly

4. Evaluate windbox pressures and air proportions. Make adjustments and perform repairs to dampers, actuators, controls and sensors. 5. Inspect the system controlling the air-to-fuel ratio. Ensure that it is correctly calibrated and functioning properly. Such inspection should include calibrating excess O2 probes and/or sensors, and adjusting overfire air systems. Any component out of calibration, in or near failure, or in a state that is likely to negate combustion optimization efforts prior to the next tune-up, should be corrected or repaired. 6. Optimize combustion to minimize generation of CO and NOX consistent with the manufacturer’s specifications. This includes burners, overfire air, firing system improvements, neural network or combustion software, control systems calibration and combustion zone temperature profiles. Add-on controls such as SCR and SNCR should be optimized to minimize generation of NOX. 7. Measure the concentration in the effluent stream of CO, NOX and O2. Measure before and after the tune-up 14

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adjustments are made (measurements may be either on a dry or wet basis, as long as it is the same basis before and after the adjustments are made). EGU’s may use portable CO, NOX and O2 monitors for this measurement. EGU’s employing neural network optimization systems need only to provide a single pre- and post-tune-up value, rather than continual values before and after each optimization adjustment. 8. Maintain an on-site annual report detailing burner inspection and tuning information. This should include CO, NOX and O2 measurements before and after tuning, description of corrective actions taken, as well as type and amount of fuel used in the prior 12 months. 9. Report the dates of the initial and subsequent tune-ups in hard copy and electronically to the EPA administrator. Data from continuous emissions monitoring systems (CEMS) should be submitted by EPA’s Electronic Reporting Tool.

About the burner system for T-Firing A tangentially fired system (Figure 1) is based on the concept of a single flame envelope. Both fuel and combustion air are injected from the corners of the furnace along a line that is tangential to a small circle, lying in a horizontal plane at the center of the furnace. Intensive mixing occurs where these streams meet. A rotational motion, similar to that of a cyclone, is imparted to the flame body, which spreads out and fills the furnace area. As one stream impinges on another in the center of the furnace during the intermediate stages of combustion, it creates a moderate degree of turbulence for effective mixing. Fuel and air are admitted from the vertical furnace corner windboxes. See Figure 2. Dampers, which control the air to each compartment, June 2014

REGULATIONS COMPLIANCE make it possible to vary the distribution of air over the height of the windbox. It also is possible to vary the velocities of the air streams, to change the mixing rate of fuel and air, and to control the distance from the nozzle at which the coal ignites to some degree. A tangentially coal-fired boiler of the 800MW class will often have 64 fuel admission locations. These are known as coal compartment assemblies and shown in Figure 3. One side of this assembly connects to the coal piping, while the assembly ends with a coal nozzle tip that is exposed to the furnace. Once coal is injected into the furnace it mixes with air and burns. Combustion efficiency and quantity of NOX and CO formed is dependent on: • Fuel properties (especially fuel oxygen/nitrogen ratio) • Heat release rates in the furnace • Furnace size and geometry • Firing system • Excess oxygen above minimum required for stoichiometric combustion • Residence time • Location, loading and balance of both fuel and air

mills, minimum steam temperature, furnace cleanliness and slagging conditions need to be understood. Proper planning should be confirmed to ensure that no one is placed in a potentially hazardous situation during any phase of the program.

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A correctly tuned boiler will not generate excess CO, which is indicative of insufficient air, poor mixing and unstable combustion. The general behavior of boiler emissions as a function of excess air is shown in Figure 4.

Work practices found in a comprehensive program A comprehensive program starts with preparation and then includes three additional elements. Preparation Before beginning, familiarize yourself with the firing system and field equipment, review past tuning and boiler inspection reports. Acquire recent fuel analyses since the type of fuel impacts the results. Have the I&C group calibrate field instrumentation (especially the oxygen analyzers, windbox to furnace pressure transmitters, and position feedbacks on secondary air dampers and tilts for T-Fired units). Next, devise a plan about what adjustments should be made to the boiler, based on the equipment available, and how/when to collect the required data. Be sure to understand all operational constraints and known unit operating problems. Safe operations are critical, so issues with tilts, dampers, controls,

Figure 4. NOX, O2 and CO relationship

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REGULATIONS COMPLIANCE

Figure 5. Damaged nozzle tip

Baseline inspection prior to shutdown A unit walk down and baseline NOX, CO and O2 measurements must be made prior to the unit being shutdown to perform the required MATS inspections and maintenance. The unit walk down can identify broken elements and large furnace air-in leakage. Flame conditions also should be recorded. Mechanical inspection during shutdown Inspection of the coal nozzle tips, stationary nozzle or burner Figures 6a and 6b. Proper flame attachment barrel and inlet elbow for wear and distortion is absolutely required. Particular attention should be directed to conditions that could be detrimental to designed primary coal/air stream delivery and mixing. Remember, the equipment must be in a suitable condition to allow operation until the next outage. An example of damage observed during an inspection of a coal nozzle tip is shown in Figure 5. Check the condition and operability of all Secondary Air Dampers and Tilt mechanisms (on T-Fired units). Since the performance of the pulverizers directly impacts the fuel/air ratio and fineness of the coal being delivered into the furnace, it also is necessary to inspect all equipment in and surrounding the pulverizer for correct operation. Boiler fuel-to-air ratios and pulverized coal fineness both have direct effects on NOX emissions.The EPA website contains additional specifics on items to be inspected. Any mechanical items identified need to repaired within 30 days (or at the discretion of the operator in the case of mechanical items that do not impact emissions performance). Post inspection boiler tuning After the unit returns to service combustion system, tuning needs to be performed by running a properly planned para16

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metric test campaign. Operational adjustments must be varied in an incremental, step-by-step process, allowing for steady state performance between changes with results recorded accordingly. It is advantageous to have boiler tuning experience during the test, since many items need to be considered and prioritized in obtaining optimum operating points that achieve the tuning objective efficiently. These include stability of ignition at the coal nozzle tips, ignition points on coal nozzle tips, furnace color and activity, identification of CO pockets, and awareness of furnace slagging and fouling conditions. Figure 6 shows an example of flame attachment on a low NOX coal nozzle tip. Proper attachment is important for low emissions, but combustion in the tip will lead to a failure. Since oxygen levels are critical to a properly tuned boiler, it is important to set up an O2 measurement test grid prior to the air heater. A grid will provide detailed information about pockets of flue gas conditions that the normal O2 probes will miss. Adding CO and NOX measurements to this grid provides an additional level of feedback that can pinpoint the sweet spot between balancing emissions requirements and boiler efficiency. Understanding of the fuel being fired is critical since variations in volatile matter, fixed carbon and ash content can dictate the appropriate tuning approach. The resulting parametric information gathered during the tuning process is used to develop operating curves and set-points for the control system. Careful attention must be directed at keeping records of all the activities just mentioned. This includes detailed records of pre- and post-inspection emissions, details of the mechanical inspections, details of equipment serviced and details of the control system updates made.

Conclusion EGU’s are required to comply with MATS regulations. The portion concerning tune-ups is straightforward but does require involvement of personnel familiar with firing equipment maintenance, combustion tuning and testing for NOX, CO and O2. Alstom routinely supplies field service and testing personnel to assist in MATS compliant inspection, tuning and testing activities. This includes more than 250 equipment commissionings performed as part of new unit startups and low NOX retrofits. Thirty-six of the 40 lowest emitting NOX units (upstream of SCR) were commissioned by trained Alstom personnel working closely with a customer team. ~ Jim Sutton is director of Growth Initiatives in Alstom’s Boiler Service Organization. He has more than 30 years of experience in power generation and is a member of ASME and a licensed professional engineer in the state of Connecticut. He has been awarded 6 patents and presented papers on topics of interest to power plant operators. Areas of special interest include boiler reliability, efficiency and advanced controls. You may contact him by e-mailing editorial@woodwardbizmedia.com. Tony Criswell is the product manager for Technical Services in Alstom’s Boiler Service organization. He has 16 years of experience in power generation with a Chemical Engineering degree from Montana State University and a MBA from Indiana University. You may contact him by emailing editorial@woodwardbizmedia.com.

June 2014

MR. MEGAWATT

Looking past the usual suspects By Frank Todd, True North Consulting

Mrs. Megawatt and I love to watch British mysteries; the ones made years ago before they decided to show everything in graphic detail. Every once in a while, they would have a situation where everyone thought they knew “who done it” and would round up the usual suspects. The thinking was that if they “done it” once, they would do it again. Inevitably it would turn out that the least likely person would be responsible for the gruesome act. It would always be the sweet tempered nearsighted old spinster who wielded the large butcher knife. Power plant engineers can often fall into the same trap, as I know from personal experience. This is a story of one such trap that caused us to Figure 1 be brought in to sort out the real culprit. It was a typical spring day up on the bluff overlooking the beautiful San Juan Mountains – typical meaning either 70°F with bright sunny skies … or a blizzard. The little blinking light on my phone told me that either another possible job was on the horizon or someone who “was not selling anything” wanted to ask my opinion on a no risk investment scheme. It was the former, however, it was a little troubling to listen to the sad story at the other Figure 2 end of the line. Apparently Big Borg Electric Corp. was in the process of downsizing and the engineer who left the message was concerned that the recent problem might affect exactly where the knife would slice. Big Borg had just assimilated the Silver Nugget Atomic Power Plant - Utah Power SNAPP–UP, or as it is known now, BB SNAPP. The plant had been experiencing a gradual decrease in electrical output corrected for condenser pressure. Lori, the plant engineer, had evaluated the condition and brought in the Big Borg experts to help out. Based on the decline in plant first stage pressure and final feedwater temperature, they concluded that the feed nozzle used to determine core thermal power was fouled. There was a lot of industry operating experience on this issue and their plant parameters looked similar. Lori was not sure and wanted to do some more evaluation, but the plant management brought in the Borg central committee and they did a full root cause investigation, concluding that the issue was nozzle fouling. SNAPP is a Nuclear Pressurized Water Power Plant with two stages of reheat for the steam being supplied to the low pressure turbines. To solve the problem, the BORG central committee concluded that they should install an ultrasonic flow

meter. The meter was installed in the next outage and everyone was doing the victory dance. Unfortunately after a few months, the music stopped and it appeared that the problem was still there. Now the central committee and the experts had somehow disappeared and the plant managers were looking at Lori with that “rightsizing” gleam in their eyes. Objectivity is sometimes hard to come by, so I had to find someone who could look past the usual suspects. That person was Kenneth F. Power, aka KP. Based on a cursory look at the plant data, see Figure 1, it did look like a poster child for nozzle fouling. KP had a lot of years’ experience in trying not to be fooled by what he was seeing in the data. Sometimes the issue is related to not looking in all the right places, so KP asked Lori to send us some data , and after choking on the number of points we asked for, she set up the download and went for a long cup of java. After reviewing the data, KP and I decided that something did not look right. An intial look at the heater extraction pressure showed that it did decrease like first stage pressure, but it decreased too much. See Figure 2. If you look at both these graphs, you might say that they changed about the same except for the fact that First Stage

June 2014 ENERGY-TECH.com

MR. MEGAWATT changes 1 percent, the extraction pressure at stage 4 should change about 1 percent. This is what happens when nozzle fouling occurs. Since power is controlled and power is essentially linear with feedwater flow as the flow error increases, the power error increases and changes the actual flow through the turbine. Therefore, when the extraction pressure decreased more (percentage wise) than the 1st stage pressure, we knew that the problem was somewhere in the cycle instead of at the flow nozzle. Figure 3 We gave Lori a call and let her know that something was amiss, she told us that we should be careful when Pressure decreased about 0.7 percent and extraction pressure going against a recommendation of the central commitdecreased about 2.2 percent. Sometimes we can be fooled by tee, since she had personal experience in that realm. This meant something as simple as scaling. Often it is a good idea, when that we had to break out the thermodynamic model and see if dealing with turbine cycle pressures, to put everything in perwe could come up with a scenario that refuted the plant data. centage by dividing the measurement by the nominal value. After we reviewed all the data, we decided that the most This is also called normalization. In this case, the extraction likely causes would either be in the turbine, moisture seppressure decrease more than two times the 1st stage pressure. arator reheater (MSR) system or the feedwater heaters. After If the problem were related to feedwater flow measurement, looking at the turbine and the feedwater heaters, we decided all the pressures connected to the turbine should decrease about to model bypass leakage on the moisture separator. Since the the same percentage. The turbine is like a set of fixed orifices â&#x20AC;&#x201C; extraction steam pressure dropped more (in percent) than the a change in steam flow through the orifices will affect all of the first stage pressure, it could be that high moisture steam was pressures about the same percentage. See Figure 3. getting past the moisture removal chevrons and causing an As the throttle valve position changes, the flow changes overloading of the 1st stage reheater, which gets its heating and all the pressures at the stages will change approximately steam from the same place as the feedwater heater extraction the same percentage as the flow change. So, if the steam flow steam. Figures 4 and 5 show the results of this modeling. The percent change in the extraction steam pressure was much higher than the percent change in the 1st stage pressure. Approximately 0.6 percent for 1st stage pressure and almost 1 percent for the extraction pressure. We placed all this analysis into a nice package, sent it off and were invited to meet with the central committee. from Ken and I dug around for some suitable clothing, hopped on a plane and presented the case to plant management. Ken, being quite loquacious, was able to convince them that while the original interpretation of the data could be part of the problem and was Archived webinars Our technical webinars are free therefore â&#x20AC;&#x153;correctâ&#x20AC;? that when looking at Makeup Water and feature industry experts other parameters there were other possible Performance & Reliability causes for the lost generation. The plant presenting the most relevant Condenser Retrofits manager gave us an understanding look subject matter as it relates to (he also did not want to ruffle the central Hydrogen Safety committee feathers) and asked what our electric power generation. Now Turbine Outage Optimization recommendations were. We suggested that Equipment Reliability Programs archived on www.energy-tech. they inspect the moisture separator during Turbine Testing with Cycle Isolation the next outage and provided a list of things contentshelf.com/shop! to look over. Steam Generation Chemistry Turned out that not only did they have Power Generating Assets an issue with bypass flow around the moisSteam Turbine Failure ture separator section of the MSR, but they Feedwater Heater Troubleshooting also had considerable wear on the passages

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June 2014

MR. MEGAWATT

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Figure 4

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around the reheaters. After an application of a few steel plates and a generous amount of welding rod, everything was sealed up and things returned to normal. Instead of Lori being “rightsized” she was offered a promotion to the central committee, which she promptly turned down, and was then left to her own devices as a plant engineer; at least until the next round of reorganization. Mrs. Megawatt and I settled down to see what the “little Belgian detective” was up to and I pondered again just how often we are misled by not looking at all the clues. ~ Mr. Megawatt is Frank Todd, manager of Thermal Performance for True North Consulting. True North serves the power industry in the areas of testing, training and plant analysis. Todd’s career, spanning more than 30 years in the power generation industry, has been centered on optimization, efficiency and overall Thermal Performance of power generation facilities. He can be contacted at editorial@ woodwardbizmedia.com.

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ASME FEATURE

Taking on Goliath: Implementing an effective RAM program for an existing power plant By Brian Wodka, RMF Engineering Inc.

Here is a quick story about a power plant. It begins with an operator promoted to chief with all the intentions and motivation to make the plant a run like a top. Before long, reality sets in and he becomes aware of the mixed-and-matched components, the make-shift ‘temporary’ solutions that have be implemented for years, and problems that have been ignored or covered-up by the previous plant chief. The dream escapes as our chief ’s ambition is beaten into submission by bureaucratic red tape, personnel drama/grudges, and the ever shrinking budget to meet ever increasing requirements and regulations. Soon all he’s trying to do is nurse the power plant a few more years until he can retire. Then one of the operators under him gets promoted and the cycle continues. This is a tragic story, but for many older power plants, it also is an unfortunate legacy. When the plant was originally built, no one had any idea that the facility would have grown to the size it is today, and so no plans were made to accommodate the growth. Portions of the facility might be 100 years old or older! The power plant is a victim of success. Figure 1. Reactive maintenance: Many power plants still have ‘To Do’ lists to prioritize their reactive Most of additional equipment was wedged maintenance. into a very limited footprint by any means adequate budget. Many have developed simple risk-based possible, with little or no thought to mainreliability programs, and some even have full reliability, tainability – and even less about replacement. The power availability, maintainability (RAM) programs. plant’s operation is not very stable, but the best that could For those of us not among the lucky few, trying to get be done with what was given. an existing power plant to incorporate these ideas seems to But not all power plants are living this tragic story. be an insurmountable challenge – a Goliath, with us in the Some operate with stable availability and have an effective role of David. maintenance program with ample staffing. Many are newer plants that were lucky enough to have the available space Facing the giant to accommodate growth. Some were also lucky enough to So how can the vicious cycle be broken? With the have the resources and administration that understood the extent of the complications and problems, it might seem importance of investing in infrastructure and providing an

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ASME Power Division Special Section | June 2014

AsME FEAtUrE ASME Power Division: Reliability, Availability & Maintainability Committee

A Message from the Chair

Figure 2. Plugged condenser tube: Addressing the symptom and not the problem.

Figure 3. Improper operation: The rear tubesheet of a firetube boiler with major tube leaks.

that the easiest option would be to simply cut your losses and try a clean start. But with an existing plant, the idea of building a brand new power plant is not an option. So how do you go about ‘clean start’ with an existing plant, especially one that might be more than 100 years old? How do you start to take on Goliath? The first step is to face the opposition head on. This means listening to the arguments of nay-sayers who are resistant to change. These are not just crotchety old operators (who also resisted computers and cell phones), but also upper management who only ask about initial cost without asking about life-cycle cost. In order for any program to work, it must have buy-in from all parties and be driven by upper management. When you listen to the opposition, there are a couple of resisting arguments that are usually involved:

June 2014 | ASME Power Division Special Section

These are exciting times for the industry of power plants and power generation. The exploration of new and renewable technologies, the recent discovery of an “ocean” of domestic natural gas, and the beginning of a gradual transition from dependency on coal. Ultimately there is a tremendous pressure causing a shift in culture. The world is depending upon industry organizations to bridge the gap between what the populous wants, and what can practically be done. The Reliability, Availability, Maintainability (RAM) of Power Plants committee is on the forefront of this culture shift, with a new standard recently issued and another rapidly in development. The open-mindedness of the committee addresses the need for change, but also is well grounded in the realities of what a power plant needs and how it operates. There has been a boost in interest, participation and utilization of the committee and the new standard. In the ASME RAM-1-2013 standard, the concept of RAM is purposely defined at a very high, broad level to permit applicability to all types, sizes and applications of power plants. It is a performance-type standard which describes a components and the process of developing a RAM Program. It derives its versatility and greater range of use by not being a prescriptive-type standard. The intent is not to preclude emerging technologies, but to make sure they are well grounded in sound engineering and triedand-true methods to ensure they do not lose perspective of the key necessity of a power plant – availability. Resisting change is the same as embracing obsolescence. It is the responsibility of experienced power plant operators such as yourselves to be educated and involved with these new standards and technologies so that your years of experience are not lost, but instead heard, incorporated into the changing times and appreciated. Be active in the professional community and share your knowledge – you have something to offer, and something to gain. For all these reasons and more, there is a very good chance that you will be hearing a lot more about RAM in the next few years. Please consider joining us. Brian Wodka RMF Engineering Inc.

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ASME FEATURE

Figure 4. Improper operation: The rear tubesheet of a firetube boiler with major tube leaks.

“This is an enormous task that is too difficult and too expensive.” This statement attempts to have the idea fail before it starts. It implies that the current condition is better than investing in improving it. “It will require a change in culture with which the existing staff may feel uncomfortable.” The effort in changing is viewed as additional work to an already overworked staff. However, it is the “comfortable” culture that is keeping the power plant in its current condition. “In the transition, the barely stable power plant will be exposed to greater risk.” Through the process, the power plant still has to operate. It needs to be understood that a temporary increase in risk is worth a permanent reduction in risk. There is some degree of legitimacy in each of these statements, but it also must be understood that doing noth-

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ing is not an option. This is the battle cry for change. The status quo has proven to be unacceptable and taking on Goliath is a risk worth taking.

Approaching the giant You need to size-up the opponent. Identifying the risk, quantifying it and communicating it are the first steps in making a change. This provides the justification for the change, backed by data. Without it, it will be second guessed and will die on the vine. But if you ask exactly how to go about approaching the colossal task, as well as implementing, training and sustaining it, most would not know where to begin. Let’s look at three basic steps: 1. Get manpower: Large power plants are a complex system of systems, each with interdependencies and compounding effects that no one may fully understand. Add to the mix the complexities of personnel, management and a little bad luck, and you have your hands full all the time. Plant personnel do not have the extra time to take on the additional effort to implement a new RAM program. Tasking people

ASME Power Division Special Section | June 2014

ASME FEATURE with more work, who already have a full time job, will not work out well. Even though identifying risk will be a task that requires intimate communication with the operating personnel, it will probably be best performed by an outside source (third-party or different department). 2. Quantify risk: What is the value of a power plantâ&#x20AC;&#x2122;s availability? How about the equipment reliability? Or maintainability? It is the job of a power plant manager and operator to make sure these things are continuously addressed, yet many (sometimes important) people forget the value of what you do. It can be difficult to put a value on the risk you reduce, but it should not be underestimated because it is the critical point that justifies what you do. You have to be able to quantify risk. 3. Buy-in: Any plan that potentially changes the existing process and culture will be met with skepticism, criticism and fear. Unless the idea is backed by management, all the way up the chain (vice presidents, chairmen, etc.), it is doomed to failure by resistance. The easiest way to get upper management buy-in is to show them the risk in dollars. When it comes to risk, do not be surprised about the value of having an available power plant. Without steam, chilled water or electricity, it is not uncommon for a large hospital, utility power plant or research laboratory to approach $1 million dollars a day! Regardless if it is millions or thousands, once you can put a number on the value of what you do, it makes building your case for resources to attack the giant much easier!

is over. It is defining the end result that tends to be more difficult. Most people can describe what they want in an availability program as if they were describing Xanadu. This dreamy, unrealistic idea of reliability paradise is counterproductive. What needs to be directly addressed is the pragmatic day-to-day implementation of how the plant operations and maintenance can occur to improve reliability and maintainability. Luckily, there are standards and case studies out there that can be used as guidance. You will find most

Attacking the giant So now you have the lined-up the manpower and the money, sometimes the hardest part of any task is getting started. So where do you start in developing an effective availability plan? Typically, you need to know where you are and where you want to be. You need a clear, comprehensive understanding of the current condition. Then you need just as clear an understanding of what you want when it

June 2014 | ASME Power Division Special Section

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ASME FEATURE related either to government entities (DOD, NASA, etc.), nuclear facilities or an industry standard (ASME RAM-1). What techniques are used to ensure availability of critical systems such as electricity, steam or chilled water? You may be surprised (or maybe not!) that it is usually just redundancy. The plant is filled with unreliable equipment and reactive maintenance. It is kept alive due to the fact there are N+1, N+2, or N+3 (or even more) redundancy. Even with all that redundancy, it seems like operators are putting out one fire after another just to keep things going. But from the outside, everyone thinks everything is going just fine since they still have a constant supply of steam, chilled water and electricity. No one realizes just how close they are every day to an outage. Redundancy is just one tool in the toolbox. Reliability engineering is an entire field of engineering that has many cost effective methods of improving the reliability of the equipment, the systems and the plant. There are basic necessities that are required in order to start making a change. These include a complete set of accurate drawings and identifying the criticality of the equipment.

Killing the giant One would think that for some of these large facilities extensive engineering calculations and elaborate reliability

models would be utilized, but unfortunately many power plants do not have a true understanding of the value of investing in reliability engineering. Reliability can be as simple as adding a redundant pump or as complicated as developing NASA-style engineering models. What is important to know is that it can be tailored to your plant’s specifics needs and budget. The results of good reliability engineering, regardless of cost, should still be accurate; it is the precision for which you pay a premium. In general, the level of precision that is most effective and practical is usually far less expensive than expected. This is what destroys the myth that implementing reliability engineering is cost prohibitive.

Conclusion A good reliability, availability, maintainability (RAM) program is properly tailored to the goals, budget and personnel requirements of a specific plant. It can be approached in many different ways, using many different techniques and formats. The ultimate goal is utilizing the resources available with reliability engineering and modern maintenance techniques to customize a RAM program that meets your plant’s availability needs and budget. Establishing a RAM program might be the only thing between you and a reliable, available and maintainable power plant. ~

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Brian Wodka leads the power plant assessment and reliability team at RMF Engineering Inc. He has performed power plant assessments, boiler inspections and forensic analysis for the last 12 years and is the chair of the ASME Reliability, Availability, Maintainability (RAM) Technical Committee and the vice chair on ASME’s RAM Standards Committee. He has a bachelor’s degree in Marine-Mechanical Engineering from the State University of New York Maritime College, a master’s degree in Thermo-Fluid Mechanics from Johns Hopkins University; is a commissioned boiler inspector with the National Board of Boiler and Pressure Vessel Inspectors and a licensed first class stationary engineer (Maryland). You may contact him by emailing editorial@woodwardbizmedia.com.

ASME Power Division Special Section | June 2014

TURBINE TECH

The importance of pure, dry hydrogen cooling gas By John Speranza, Proton OnSite

Power plants need to do all they can to produce electricity safely and efficiently. The good news is that there’s a relatively simple switch that can have a big impact on a plant’s ability to maximize its electricity output and improve its overall safety. Many plants rely on large amounts of stored hydrogen as a cooling gas for generators, an approach that can cause increasFigure 1. Northern Power Station in Port Augusta, South Australia, switched from bottled hydrogen to an on-site hydrogen genes in windage losses and erator to supply its two 260MW turbines with cooling gas. It improved purity levels to increase efficiency and reduced dew points moisture build-up in the to safe levels. generator casings. These issues affect the efficiency on-site. Fifteen cylinders of hydrogen gas have the explosive of electricity production, and also increase the risk of a catequivalent of 525 lbs of TNT. Chellachamy said the station astrophic accident. had to adhere to two different sets of onerous safety regulaForward-thinking plants like the Northern Power tions to handle and store this much hydrogen. Station (NPS) in South Australia recently swapped its “The constant need to handle large hydrogen cylinders, hydrogen gas storage tanks for an on-site hydrogen generchange crates and clear lines meant there was always an ation system, a change that helped improve generating effiissue of safety,” he said. ciency and made the facility safer. The NPS in Port Augusta handles up to 30 percent of Impure cooling gas leads to windage losses the base load of South Australia’s power demands and, with NPS’ use of delivered hydrogen meant that its turbines a new H Series hydrogen generator, now has a safer and were not running at maximum efficiency. It found purer source of cooling gas. that delivered gas, which was being continuously fed into the turbines, was not high purity hydroProblems with delivered gas gen. The 520MW coal-fired power station, owned by Alinta “The purity of our delivered hydroEnergy, installed one set of H-Series hydrogen generators gen used to vary between 95 percent and two StableFlow hydrogen control systems in 2010 to and 98 percent,” Chellachamy said. supply its two 260MW turbines with hydrogen cooling gas. “We ran a batch-fed process over For years, the station received delivery of cylinders two weeks with a continuous of hydrogen gas from Adelaide, more than 185 miles bleed, which meant the gas away from the station. The production manager, Darwin within the turbine genChellachamy, from Alinta Energy’s NPS, said the station needed 30 cylinders of 6.3Nm3 of hydrogen gas each week Failure to properly to keep its two turbines constantly filled with hydrogen. ground rotating Eventually, due to delivery issues, NPS was ordering its equipment can result in hydrogen cylinders from Sydney, which is almost 1,000 miles away. The distance from its gas provider, coupled with expensive bearing, seal, & the need to have gas on hand at all times, meant the station gear damage. had to keep 15 cylinders – or 90Nm3 of explosive gas – ®

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TURBINE TECH Table 1 – Average Purity and Dew Points Before and After Hydrogen Generator Installation Turbine

Average purity before generator installation

Average purity after generator installation

Reading as of 4/30/13

Unit 1

96.52%

99.24%

99.57

Unit 2

95.35%

98.66%

99.44

Turbine

Average dew point before generator installation (°C)

Average dew point after generator installation (°C)

Reading as of 4/30/13 (°C)

Unit 1

-1.97

-3.23

-20.63

Unit 2

-11.18

-10.37

-23.26

Table 1

erators became less pure until we purged the system and started again.” All turbine OEMs agree that even small reductions in hydrogen purity directly correlate to increased windage friction losses inside the turbine generators, which have a direct impact on a power plant’s bottom line. Air is the most likely impurity to affect hydrogen within the generator casing. Air is more than 14x as dense as hydrogen, so even relatively low levels of air considerably increase the density of the gas mixture. Impurities in a hydrogen supply increase the density of the gas, and the density of a gas affects its ability to remove heat. This is shown as: Gdens = (Hpur x 1) + (Abal x 14.4) Where: Gdens = Increase in gas density (%) Hpur = Purity of hydrogen in generator casing (%) Abal = Balance of impurity (air) in generator casing (%) Roughly, for every 1 percent of air trapped in a hydrogen-cooled generator casing, there’s an average 250 kW drop in power production. And because carbon dioxide is even less thermally conductive and about 22x as dense as hydrogen, it has an even bigger impact on power production. An additional percent of carbon dioxide in the hydrogen threatens to reduce power production by more than 600 kW. Impure hydrogen means lost revenue, or increased fuel costs for a plant.

Figure 2. NPS installed a pair of Proton OnSite StableFlow gas control systems to maintain optimal gas dryness, purity and pressure inside the generators.

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June 2014

TURBINE TECH Dew point difficulties affect safety “The hydrogen gas dew point was our main problem,” Chellachamy said. NPS’ hydrogen gas cooling system only had the ability to top up the hydrogen gas inside the turbine generator casing, and its old gas dryers were unable to operate while its turbines were online. This meant the gas was too wet when it was entering the casings. This is a big problem, especially in warm climates like NPS experiences in South Australia. Ideally, hydrogen dew points should be at around -15°C Figure 3 to -20°C to ensure no condensation is formed. The temperature inside NPS’ turbines reached 60°C when they were running and ambient temperatures were high, Chellachamy said, especially in hot weather.

Moisture increases the density of the ambient gas in the casing, which affects windage, but more importantly, moisture can lead to turbine failure.

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TURBINE TECH

Figure 4. NPS installed a Proton OnSite H-Series Hydrogen Generator, which produces 2Nm3 of ultra pure cooling gas each hour, using only deionized water and electricity.

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“If moisture gets into the rotor retaining rings, they are prone to cracking and corrosion, and damage to the retaining rings can be catastrophic,” Chellachamy said. A cracked ring can burst into pieces, tearing insulation, copper and stator iron until the stator windings and core iron are gouged so deeply that the ring and rotor stop. If sufficient gouging and tearing takes place, the rotor can become so unbalanced that it can be destroyed. Explosion and fire from the flammable insulation resins, oil lines and hydrogen gas are also likely to add to the damage. Not only could condensation destroy a multi-million dollar turbine, but it also could lead to operator injury or death. NPS operators tried to refrigerate the delivered gas and also pass the gas through a desiccant dryer to reduce the dew points, but operators were only able to attain a dew point of around 0°C. “Our previous cooling system definitely had limitations,” Chellachamy noted. Moisture problems, coupled with the impurities in the hydrogen gas, meant the NPS generators were experiencing windage losses. These losses are typically stated at nominal pressure above atmospheric pressure and at some nominal purity. Total windage loss is shown as: Gloss = Gwind x (Dact / Dbase) x (Pact +14.7)/(Pspec + 14.7)

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TURBINE TECH Where: Gloss = Total generator electrical losses due to windage (kW) Gwind = Baseline generator windage loss (kW) Gnet = Net windage loss associated with hydrogen purity (kW) Dact = Actual gas density due to impurities (%) Dbase = Gas density baseline (%) Pact = Actual generator operating pressure (psig) Pspec = Generator operating pressure specification (psig)

Figure 5

Any hydrogen supply needs optimal pressure, dew point and purity to maximize output from a generator. NPS was struggling to control all these variables using a stored hydrogen gas supply, so both windage loss and expenses remained high.

Time for on-site hydrogen “At first we considered replacing our gas dryers, but drying equipment is very expensive,” Chellachamy said. “We realized it was going to be more cost-efficient to invest in a Proton Exchange Membrane (PEM) on-site hydrogen generation with a StableFlow control system to ensure that the gas that we were using was dry and pure throughout the operation of the power generator.” NPS turned to POGC in HMA Group, the Australasia local partner of Proton OnSite, which is a Connecticutbased company that designs and manufactures PEM hydrogen generators. An on-site PEM hydrogen gas generator uses only deionized water and electricity to produce 99.9995 percent purity hydrogen at 440 psig. Rather than buying 30 hydrogen tanks every month, NPS now only pays for the deionized water and electricity required to make 2Nm3 of hydrogen gas each hour. In this case, there was a payback period of slightly more than one year for the equipment. NPS also wanted to control the purity, humidity and pressure on each generator, so they also installed a pair of Proton OnSite’s StableFlow hydrogen control

systems for each steam turbine. By maintaining optimal dryness as well as purity, NPS was finally able to ensure that windage losses remained at a minimum and – more importantly – that moisture in the casings and on the rings was minimized.

Improved quality, more efficiency In just more than 12 months, NPS saw marked improvement in the purity and the dew points of its hydrogen. In

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January 2010, before the switch to on-site generation, the two generators’ average hydrogen purity was 95.95 percent and the average dew point was just -1.87°C. By March 2011, several months after installation, the average hydrogen purity in the generators had increased to 99 percent and the dew point had fallen to -9.5°C. In mid-2013, NPS’ hydrogen supply was averaging at more than 99.5 percent purity and dew points had fallen even further to -21.94°C. “Our hydrogen gas supply is now running much dryer and there is little chance of reaching ambient temperatures and experiencing moisture,” Chellachamy said. NPS still keeps a smaller supply of hydrogen gas cylinders on-site to help re-gas the generators after a purge, but now operators are ordering significantly less hydrogen gas. “We’re happy with the investment,” Chellachamy said. “The H-Series hydrogen generator is very easy to maintain and we’ve met our objectives and improved the quality of our hydrogen gas.”

On-site generation means efficiency, safety A plant that doesn’t thoroughly examine and understand how it utilizes its cooling gas will not be as efficient or as safe as a plant that takes steps to improve purity, humidity and pressure when dealing with hydrogen. NPS is benefiting from finding a better alternative. NPS, and other power plants around the world, have found that replacing stored gas with an on-site generator saves money and gives the plant operators fewer headaches. Most importantly, it’s safer. Removing the need to store highly flammable gas and at the same time reduce the risk of a catastrophic generator explosion is a win-win for any plant. With a hydrogen generator, NPS has a simple, safe and economical way to produce the more electricity that lights up South Australia. ~ John Speranza is vice president of Global Product Sales at Proton OnSite. Speranza joined Proton OnSite in 1997 and was involved in the development of Proton’s core technology and industrial product line. Prior to joining Proton OnSite, Speranza spent 12 years at Hamilton Sundstrand division of United Technologies Corp., developing PEM fuel cell and electrolyzer products for military and aerospace applications. Speranza has been granted 17 patents to date in the areas of control systems, fuel cell and electrolyzer system, and power plant efficiency and improvement. He has a degree in Electrical Engineering Technology from the University of Hartford. You may contact him by emailing editorial@woodwardbizmedia.com.

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