January 2015

Automating HRSG water and steam controls

ENERGY-TECHDedicated to the Engineering, Operations & Maintenance of Electric Power Plants

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JANUARY 2015

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Ins and outs of HEP systems 5 • Vibration monitoring 13 • Training Tips 21

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5 The ins and outs of high-energy piping systemsBy John Arnold, Niantic Bay Engineering, and Marshal Clark, Investigative Engineering Corp.

9 HRSG water/steam chemistry control: Automating the processBy Brad Buecker, Energy-Tech contributor

CoLUMNs

13 Maintenance MattersVibration monitoring considerations in high EMI environmentsBy Shalvi Desai and Renard Klubnik, Meggit Sensing Systems

21 Training TipsProgrammed instructionBy Harold Parker, HPC Technical Services

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15 Justification for long-distance transmissionBy Nathan Smith, University of Maryland, Baltimore County, and Alex Pavlak, Future of Energy Initiative

iNdUstrY NotEs

4 Editor’s Note and Calendar

23 Advertisers’ Index

24 Energy-Tech Showcase

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4 ENERGY-TECH.com JANUARY 2015

What to expect in 2015Exciting changes, consistent quality from Energy-Tech

Editor’s NotE CALENdAr

January seems to come faster every year and it’s hard to believe that this year marks my eighth as the managing editor for Energy-Tech magazine. Time really does fly when you’re having fun.

As we go into the New Year, here’s a Top 5 list of things to look forward to from Energy-Tech magazine.1. Continued digital growth – Whether you’re visiting our website, Facebook page, LinkedIn group or Twitter, Energy-Tech’s digital presence is growing and will get

even stronger in the coming year. If you haven’t “Liked” us on Facebook yet, joined our LinkedIn group or started following us on Twitter, please do today. You’ll be glad you did.

2. Technical expertise from trustworthy contributors – Energy-Tech’s contributors are recognized experts in the industry and we will continue to highlight their projects and advice throughout the coming year. Do you have a particular question or topic you’d like to see addressed? Please let us know by emailing [email protected]. Our contributors love to answer reader questions and help solve problems.

3. New voices in the magazine – In addition to the columnist and contributors you trust, Energy-Tech will continue bringing new voices into the magazine. A great example of this is in this month’s ASME article, Justification for long-distance transmis-sion, by Nathan Smith from the University of Maryland, and Alex Pavlak. Smith won ASME’s inaugural student paper com-petition this year and we’re excited to share his work with you.

4. Online learning opportunities – Energy-Tech’s webinar learning opportunities will continue in 2015, so keep an eye out for emails about upcoming course opportunities. And again, let us know if there are any topics you would like to see specifically addressed. These have grown in popularity since we began and we want to make sure we’re giving our attendees the informa-tion they need – so let us know!

5. Strong relationship with the ASME Power Division – We include their articles in every issue of the magazine and many of their members have become regular contributors to Energy-Tech in the past few years. This is a partnership we will continue to develop, and we hope you’ll join us.

I’m looking forward to what the coming year has in store – I hope you are too and that we have a chance to meet you, whether at a con-ference, through a webinar or even via email. In the meantime, thanks for reading.

Andrea Hauser

Feb. 16-20, 2015Introduction to Machinery Vibrations (IMV)Tempe, Ariz.www.vi-institute.org

March 23-27, 2015Basic Machinery Vibrations (BMV)Knoxville, Tenn.www.vi-institute.org

April 21-23, 2015Electric Power Conference & ExhibitionRosemont, ILwww.electricpowerexpo.com

May 11-15, 2015Advanced Vibration Analysis (AVA)Houston, Texaswww.vi-institute.org

June 15-19, 2015Rotor Dynamics and Modeling (RDM)Syria, Va.www.vi-institute.org

June 28-July 2, 2015ASME Power & Energy 2015San Diego, Calif.www.asmeconferences.org/powerenergy2015

Sept. 21-25, 2015Machinery Vibration Analysis (MVA)Salem, Mass.www.vi-institute.org

Oct. 12-16, 2015Balancing of Rotating Machinery (BRM)Knoxville, Tenn.www.vi-institute.org

Nov. 30-Dec. 4, 2015Advanced Vibration Control (AVC)Houston, Texaswww.vi-institute.org

Submit your events by emailing [email protected].


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The ins and outs of high-energy piping systems

By John Arnold, Niantic Bay Engineering, and Marshal Clark, Investigative Engineering Corp.

Historically, high-energy piping (HEP) system assessments in fossil-fuel power plants were performed to satisfy a utility or plant-driven desire to avoid failures and achieve indus-try-common goals of safe and reliable operation. The assess-ments would support this through the timely detection of service-related damage. While some insurance carriers might have fostered such activities, jurisdictional mandates general-ly were not applied to piping condition assessment activities. This is a significant deviation from the nuclear power industry, where in-service inspection is a common activity in operating plants. The publication of the 2007 Addenda of the ASME B31.1 Power Piping Code closed the gap between the power industries by requiring a program for the in-service assessment of selected (or “covered”) piping systems designed and built to that edition of B31.1, or later. This article is intended to pro-vide an overview of these requirements and an understanding of the more common damage mechanisms that are required to be addressed, as well as an additional concern for owners of more modern plants containing Grade 91 steels.

High-energy piping systemsThe phrase “high-energy piping (HEP) system” is a generic

description of piping that operates at elevated temperatures and pressures. There is no defined threshold for “high-energy” or “elevated,” and the definition of an HEP system can vary from plant to plant. In general, the classification is applied to those systems where there is concern about component fail-ure and the potential for personnel safety and consequential damage. For conventional power plants, these systems include the main steam piping, hot reheat piping and cold reheat pip-ing. Sometimes boiler components such as outlet headers and boiler external piping are added to the mix, as are feedwater piping systems. Combined-cycle plants typically lump the high pressure steam, hot reheat, cold reheat and low pressure steam systems into their definition. Combined-cycle plants also might include boiler (HRSG) components and feedwater sys-tems into their definition.

HEP systems operate at conditions where a number of damage mechanisms might be active, causing wall thinning, cracking and/or degraded material properties. To avoid failures, the timely detection of service-related damage due to these mechanisms is necessary. Detection is possible through a regi-men of complimentary nondestructive examination inspection and metallurgical evaluation tools that target system and com-ponent-specific manifestations of damage. Due to the com-plexities associated with material performance, and the routine variations in plant operation, these assessments must consider

all potential damage mechanisms and modes when determin-ing the appropriate examination approach.

Regulatory requirementsGenerally HEP systems are designed and fabricated in

accordance with the requirements of ASME B31.1, Power Piping[1]. Historically these construction codes have not included requirements for the operation and maintenance of the piping systems; but following the catastrophic failures of longitudinally seam welded hot reheat piping at the Sabine (1979), Mohave (1985) and Monroe (1986) Stations, require-ments were added. Initially the 1989 edition of B31.1 added non-mandatory Appendix V to provide recommendations for plant practices to achieve both reliable service and a predict-able life in the operation of power piping systems.

Finally, in the 2007 addenda of B31.1 the new Chapter VII, was added to the main body of the document. This chap-ter, while limited in scope, established a requirement for the

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issuance of written operation and maintenance procedures for Covered Piping Systems (CPS)[2]. The CPS category includes NPS 4 and larger main steam, hot reheat steam, cold reheat steam and boiler feedwater piping systems. In addition, CPS also included NPS 4 and larger piping in other systems that operate above 750°F (400°C) or above 1,025 psi (7,100 kPa). CPS isn’t limited to those systems, other piping systems can be included if the utility determines that the system is hazardous based on an engineering evaluation of probability and conse-quence of failure.

These requirements are only needed for power piping systems constructed to the 2007 addenda or later. However, insurance providers are encouraging their clients to develop written operating and maintenance procedures for CPS con-structed to earlier editions of the code. In the future it is plau-sible that the National Board Inspection Code also will adopt requirements for operation and maintenance procedures for CPS.

Program requirementsFor CPS, B31.1 requires operation and maintenance pro-

cedures intended to ensure safe operation. The following items are required to be included in those procedures:

1. Operating procedures for the piping systems in accor-dance with design limits

2. Operating hours and modes of operation (i.e. cycles)3. Actual operating temperatures and pressures4. Documentation of significant transients or excursions

(both pressure and temperature)5. Details on piping system modifications, repairs or

replacements6. Documentation on pipe support maintenance (only for

systems operating in the creep regime)7. Documentation of piping system maintenance, includ-

ing vents, drains, valves, desuperheaters, etc.8. Identification of active damage mechanisms, including

creep, fatigue, graphitization, corrosion, erosion and flow accelerated corrosion (FAC)

9. Fluid quality (i.e. dissolved oxygen content, pH)10. Documentation of the Condition Assessment (as

described in B31.1 Paragraph 140)The B31.1 Condition Assessment Program is intended to

assess and document the condition of CPS based on assess-ments performed at periodic intervals as determined by an engineering evaluation. The extent of the assessment is not specified, but will be based on established industry practices. The assessment efforts may range from a review of previous inspection and operating history to a thorough nondestructive examination and engineering evaluation, and the documenta-tion is required to include the following:

1. System name2. Original material specification, including date/edition3. Design and actual pipe dimensions4. Design operating temperature and pressure5. Normal operating temperature and pressure

6. Operating hours (both total and since the prior condi-tion assessment)

7. Operation modes since last condition assessment (num-ber and type of cycles)

8. Pipe support walkdown data (only for systems operating in the creep regime)

9. Modifications and repairs10. Information on transient events11. Summary of inspection findings12. Recommendations for re-inspection interval and scope

Supporting information for these programs is provided in B31.1 Nonmandatory Appendix V.

Common damage mechanismsThe damage mechanisms listed in the CPS operation

and maintenance procedures are dependent on temperature and pressure. The main steam, hot reheat steam and some extraction steam lines operate at temperatures where time-de-pendent properties apply and creep damage is expected. The boiler feedwater systems are susceptible to flow-accelerated corrosion, and while steam-bearing systems like the cold reheat piping might not normally be subject to creep, they can be susceptible to thermal fatigue cracking. While exceptions are often found, the following summary can be applied for the damage mechanisms specified in B31.1:

• Creep (stress rupture) and creep fatigue: Because creep is a time-dependent damage mechanism, as a unit ages, the likelihood of creep related failures increases. Of greatest concern is the potential for a failure in longitudinally seam welded components, since these failures might be catastrophic and result in the release of large quantities of steam. Historically, creep failures at circumferential welds have occurred at welds subject to considerable bending stress, concentrating the damage to one side of the pipe and promoting a leak-before-failure event. When creep accumulates at welds that are not subject to high bend-ing stresses, the damage is expected to be more uniform around the circumference and the risk for a guillotine type failure increases, especially in association with a major transient event such as water/steam hammer.

• Fatigue: Fatigue is the phenomenon leading to fracture under repeated or fluctuating stresses that are less than the tensile strength of a material and include corrosion fatigue, thermal fatigue and mechanical fatigue. Examples of different forms of fatigue and their affect on HEP sys-tems include:• Mechanical fatigue might occur where flow induced

or mechanically induced vibration is present.• Corrosion fatigue is common in many fossil boilers,

but has only rarely occurred in HEP. A catastrophic failure of the cold reheat piping at Texas Genco’s W.A. Parish Unit 8 was attributed in part to the occurrence of corrosion-assisted fatigue initiating at


geometric discontinuities at the toe of the longitudi-nal seam weld[3].

• Thermal fatigue is a common failure mechanism in HEP where flashing or repeated wetting-and-drying occurs.

• Graphitization: Graphitization is generally defined as the accumulation of free carbon as a result of the equilibri-um decomposition of carbides (mostly Fe3C, or cemen-tite). Graphitization has been recognized within various industries for many decades and is known to affect carbon and carbon-molybdenum steels.[4] Depending on the shape and distribution of the graphite, mechanical properties might be affected.

• Corrosion: Generalized corrosion of HEP systems in base-load units is not common; however, units operating in a cyclic manner or for peaking might be subject to corrosion. Corrosion generally occurs on the inner surfac-es of piping systems low points, but external corrosion due to corrosion under insulation can affect all types of piping systems if the piping is not protected with sealed insulation cas-ing or other appropriate protective coatings.

• Erosion: Similar to corrosion, erosion is more commonly found in the lower temperature piping systems that contain water. Erosion is the wastage of metals by the abrasive action of moving fluids, and is often exacerbat-ed by the presence of solid particles or other matter in suspension. Steam erosion, while commonly found to be the cause of consequential damage in superheater tube leak events, is not commonly found in steam piping.

• Flow Accelerated Corrosion (FAC): FAC is the result of the localized dis-solution of the otherwise protective magnetite (Fe

3O

4) film that forms

along the internal surface of piping component systems exposed to steam, feedwater and condensate.[5] The dis-solution of the protective magnetite exposes the underlying pipe surface to potentially rapid corrosion. FAC does not occur in superheated steam, since a liquid film must be present for the corrosion process to occur. FAC is characterized as single-phase, occurring in water piping, such as feedwater and condensate piping, or

two-phase. Two-phase FAC occurs when the steam is at saturation and flashing occurs. Systems subject to two-phase FAC include the heater drains, the deaerator and low-pressure heater shells.

Creep strength enhanced ferritic steelsWhile the development of operation and maintenance

procedures for traditional units is important, owners of facil-ities using the newer creep strength enhanced ferritic steels, like Grade 91, will especially benefit from these procedures. Creep strength enhanced ferritic (CSEF) steels were specifi-

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cally developed to provide exceptional strength at the elevated temperatures commonly experienced in the power generation industry. CSEF steels achieve these properties though a care-ful mix of additive elements that vary based on the alloy. For Grade 91, the strengthening is due in part to a complex system of nitrides and carbonitrides that form during fabrication and heat treatment.

The strength of these CSEF alloys is based on careful ther-mal processing and improper fabrication or manufacturing practices that can create material microstructures that do not exhibit the strength anticipated by the designer. In many cases, improper thermal processing has resulted in creep rupture fail-ures after a relatively short incubation time. Commonly these failures have occurred at field-fabricated welds, pipe bends and castings (e.g. valves). Another concern with creep strength enhanced ferritic steels is improperly heat-treated materials and welds.

The immediate emphasis is on addressing lower-bound property material, but “good” material also can be expected to incur damage, albeit at a slower rate. Moreover, in addition to maltreated base metal having increased susceptibility to dam-age, accompanying welded locations can be expected to expe-rience even higher rates of damage accumulation that include creep initiation at outer surface and subsurface positions or stress corrosion cracking.

ConclusionsThe power generation industry has found that a periodic

assessment of high-energy piping systems (or covered piping systems) is an important tool to avoid failures and achieve industry-common goals of safe and reliable operation through the timely detection of service-related damage. Until now, these assessment programs have been voluntary, and performed at the urging of underwriters and jurisdictions.

However, it is important to understand the program goals with respect to the damage mechanisms of concern to opti-mize the use of personnel and budgets. In-service examina-tions do not, in themselves, correct in-service damage or oth-erwise mitigate failures. In fact excessive inspection can utilize necessarily limited maintenance budgets and take away from the performance of other prudent maintenance activities.

The changes in ASME B31.1 strengthen program require-ments, and make these programs mandatory for newer plants. Given this foundation, it is likely that jurisdictional and insurance agencies will consider expanding the requirement to older equipment. These programs, if properly set up and executed, do not need to be onerous and can work smoothly within the existing plant operations and maintenance struc-ture. ~

References1. ASME B31.1-2012, “Power Piping” ASME Code for

Pressure Piping, B31, The American Society of Mechanical Engineers, Three Park Avenue, New York, New York, June 29, 2012

2. Frey, J., “High-Energy Piping Systems Are Now Covered Piping Systems,” ASME PVP2010-2; Proceedings of the ASME 2010 Pressure Vessels & Piping Division/K-PVP Conference, July 18-22, 2010, Bellevue Washington

3. Guidelines for the Evaluation of Cold Reheat Piping, EPRI Palo Alto, CA: 2005. 1009863

4. R.W. Emerson, “Carbide Instability of Carbon-Molybdenum Steel Piping,” Presented at the Annual American Society of Mechanical Engineers Meeting, New York, NY, December 1943.

5. Guidelines for Controlling Flow-Accelerated Corrosion in Fossil and Combined Cycle Plants, EPRI, Palo Alto, CA: 2005. 1008082

John Arnold has been helping utilities manage aging fossil plant assets for more than 20 years through the development of comprehensive assessment programs, field engineering evaluations and laboratory metallurgical testing. His work is mainly focused on boilers and the evaluation of water and steam-touched tubing and the heavy-wall pressure parts. He has worked with Structural Integrity Associates since 2005 in its Fossil Plant Services group, focusing on the nondestructive testing of boiler tubing. Arnold has a master’s degree in Metallurgy and Materials Engineering from the University of Connecticut, and is a member of ASME’s Steam Generators and Auxiliaries Committee. You may contact him by emailing [email protected]. Marshal Clark is an engineer with Investigative Engineering Corp. You may contact him by emailing [email protected].

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Decades of direct experience by power plant personnel and R&D work by such organizations as the Electric Power Research Institute (EPRI) and the International Association of the Properties of Water and Steam (IAPWS) have shown how critical proper water/steam chemis-try control is in utility boilers. Even seemingly minor excursions may lead to problems that cause forced outages due to equipment failure. These fail-ures can cost an owner hundreds of thousands to millions of dollars in lost generation and repairs. And a number of events have caused fatalities, which is the ultimate cost.

For the many combined-cycle power plants that have recently been commissioned, or are in the design stage, several factors have the poten-tial to negatively impact the ability of plant personnel to monitor and prop-erly control steam generator chemis-try. These factors include:

• Many plants are minimally staffed, with few or no person-nel having chemistry expertise.

• Chemistry control is akin to running on the razor’s edge, as modern treatment programs must be controlled within narrow windows to be effective.

• Most HRSGs are of multi-pressure design, with different chemistry requirements for each circuit.

This article summarizes current thinking regarding water/steam chemistry, and then examines technology for monitor-ing and control.

HRSG chemistry highlightsAs I have reported in previous Energy-Tech articles, most

recently in the December 2014 issue, per research conducted by EPRI, the IAPWS and others, the use of reducing agents (aka, oxygen scavengers) in power boiler condensate/feedwa-ter systems is a discredited concept unless the system contains copper alloys; virtually unknown in HRSGs. Reducing agents establish and perpetuate single-phase flow accelerated corro-sion (FAC), yet, as this author can attest, many HRSG specifi-cations issued by project developers, and often with the guid-

ance of an owner’s engineer, call for reducing agent (hydrazine or a substitute) feed to the condensate. The mindset simply will not go away. Continued education is improving the battle against FAC. The old all-volatile treatment reducing [AVT(R)] program (ammonia or amine feed for pH control and reducing agent feed for oxygen removal and metal passivation) is being replaced by AVT(O), which stands for all-volatile treatment (oxidizing). In this program, only ammonia, or perhaps an amine, is utilized for pH control with no reducing agent feed. A standard pH control range is 9.2-9.6, and ideally leaning toward the higher end of this range.

Phosphate treatment is the choice for high-pressure (HP) and intermediate-pressure (IP) chemistry control in many HRSGs. Experiences in coal-fired power plants have revealed many important factors regarding phosphate treatment that also are applicable to HRSG operation, and particularly for high-pressure HRSG circuits. EPRI developed very specif-ic guidelines and control charts for HRSG phosphate use. Important items include:

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HRSG water/steam chemistry control: Automating the process

By Brad Buecker, Energy-Tech contributor

Figure 1. An HRSG schematic with sample inputs that can be displayed on DCS and workstation screens throughout the plant. This is one of several HRSG configurations possible, but is a common design with a feed forward LP (FFLP) circuit.


• Of the various phosphate compounds, only tri-sodium phosphate (Na

3PO

4) should be utilized, since other phos-

phate species can establish corrosive deposits on boiler internals.

• Above 300°F, phosphate solubility greatly decreases. Thus, at normal loads much of the phosphate may precipi-tate on the boiler waterwall tubes. This phenomenon is known as “hideout,” and the mechanism can negatively influence chemistry control. Therefore, in high-pressure steam generators most programs are operated with a bulk phosphate concentration of under 2 parts-per-million (ppm), and often closer to 1 ppm. Higher phosphate dos-ages are possible in the IP due to the lower pressure and heat flux. For HRSGs where the LP evaporator serves as a heating source for HP and IP feedwater, solid alkalis are not permitted as a treatment method, since they can be introduced directly to main steam via the attemper-ators. Rather, the ammonia or amine used for conden-sate/feedwater treatment also serves as the pH-condi-tioning agent in the LP circuit.

• The free caustic (NaOH) concentration should be main-tained at less than 1 ppm, since otherwise under-deposit caustic gouging is possible.

• A properly maintained TSP program, with perhaps a bit of caustic addition at unit startups, will maintain the pH within the range (9.0-10.0) shown on control charts.

Alternatives to phosphate treatment in the HRSG include caustic treatment and AVT. For caustic treatment, the 1 ppm free caustic limit must be rigidly maintained, again due to potential difficulties with under-deposit caustic corrosion.

Even when chemistry appears to be under control, impu-rity ingress from a condenser tube leak or other sources might cause significant to potentially severe problems. Contaminants, and especially chlorides, can initiate corrosion fatigue, under-deposit corrosion and hydrogen damage in high-pres-sure steam generators. This is why EPRI lowered the normal limit for condensate chloride, sulfate and sodium concentra-tions to 2 parts-per-billion (ppb) in units without condensate polishers.

The 2 ppb limit for chloride and sulfate also was established for steam, since it’s known that trace concentrations of these impurities can lead to pitting, stress corrosion cracking and corrosion fatigue in turbines. Some researchers think that even

the current 2 ppb requirements for impurities such as chloride are too lenient.

Monitoring and controlSo, for those plants with limited staff to monitor and con-

trol water/steam chemistry, how can adequate measures be established? A key is to equip the plant with the necessary on-line instrumentation to monitor all important parameters. In today’s climate, where capital funds may be tight, plant designers often cannot select a sample panel and system with every desired analysis. The following discussion outlines the most important on-line analyses, and why they are so import-ant. The list is based upon the three-pressure HRSG shown in the schematic below.

Condensate pump dischargeThe condensate pump discharge (CPD) is a critical mon-

itoring point, since steam surface condensers are the most likely source for major contamination. Condenser tube leaks on unpolished systems have been known to cause boiler tube failures within days, sometimes even hours.

Recommended on-line analyses are:Core on-line

• Degasified Cation Conductivity (D.C.C.)• Sodium• Dissolved Oxygen (D.O.)

Degasified cation conductivity is a method to quickly detect contaminant in-leakage from failed condenser tubes. In drum-type steam generators, the cation conductivity should be maintained at less than 0.2 µS/cm.

Sodium monitoring is an excellent and recommended complement to D.C.C. In a condenser with no leaking tubes, sodium levels in the condensate should be very low, <3 ppb, and in many cases less than 1 ppb.

Dissolved oxygen analyses are important for monitoring air in-leakage to the condenser. Ideally, if the condenser air removal system is operating at maximum efficiency, dissolved oxygen levels should be below 10 ppb. A sudden increase in dissolved oxygen might indicate a problem at or near the con-denser, which allows excess air, including carbon dioxide, to enter the system. Condenser shells have many penetrations, so the potential for air in-leakage is great.

Feedwater/Economizer inletThis sample is very important, since it is the last check-

point before the boiler itself. Feedwater chemistry can have a significant impact on boiler operation for several reasons. First, excessive feedwater contamination will reduce the boiler cycles of concentration and require increased blowdown. Second, improper control of feedwater chemistry might cause corro-sion of feedwater piping and heat exchanger tubes, which will introduce iron oxide particles and copper corrosion products to the boiler. Third, in many steam-generating systems feedwa-ter is sprayed into main and reheat steam for temperature con-

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Want to learn more about power plant chemistry?

For those readers who are interested in learning more about utility and industrial steam generator makeup water treatment, cooling water chemistry, lay-up and effluent issues, I invite you to consider attending the annual Electric Utility Chemistry Workshop and the annual International Water Conference. Also, please feel free to contact me directly.


trol. Contaminants are directly introduced to the superheater and turbine via spray attemperation.

Recommended feedwater analyses include:Core On-Line

• pH• Dissolved Oxygen• Specific Conductivity• Degassed Cation Conductivity• Iron (corrosion product sampling)• Sodium

The optimum feedwater pH for systems containing mixed copper and iron metallurgy is 9.0-9.3, while for strictly iron-based systems the range is higher at 9.2-9.6. The pH is con-trolled by ammonia feed, which in turn is typically controlled by specific conductivity.

Measurement of degassed cation conductivity and sodium supplement the condensate pump discharge analyses to ensure that excessive impurities are not reaching the steam generator. It also is important to ensure that impurities are not being introduced to main and reheat steam via attemperator sprays.

Corrosion product sampling for iron is quite important to ensure that the chemical treatment program is operating effec-tively. Ideally, the concentration should be less than 2 ppb.

Boiler waterAlong with condensate pump discharge, the boiler water

sample is the most important of all, especially for drum-type units. This is due to high temperatures and the concentrating effect caused by recirculation of the boiler water. These factors greatly influence potential corrosion and scaling mechanisms. Furthermore, high concentrations of dissolved solids in the boiler water can introduce excessive contaminants to the

steam, where they might form deposits and/or corrode super-heater tubes and turbine components.

Recommended boiler water analyses include:Core On-Line

• pH• Specific Conductivity• Degassed Cation Conductivity• Phosphate (for those units on phosphate treatment)

Optional On-Line• Silica

The most important analysis is pH. It must be maintained within a fairly narrow range (typically 9.0-10.0) to prevent corrosion. This measurement is the one criteria that, if the reading drops below 8.0, calls for immediate unit shutdown, provided the value is accurate and not due to instrument error. A sudden drop in pH, most likely preceded by a sudden rise in CPD cation conductivity and sodium, is a quick indicator of a condenser tube leak.

Specific and degassed cation conductivity analyses provide direct indication of the amount of impurities in the boiler water, and with some mathematical manipulation can be uti-lized to calculate the concentration of the harmful corrosive agents sulfate and particularly chloride.

Although EPRI lists silica as an optional analysis, it could easily be placed in the “Core Analysis” category. Silica must be held below pressure-dependent limits, as silica will vaporize, carry over with steam and precipitate in the turbine. This effect becomes dramatic as pressure increases. For example, in a 900 psi boiler the recommended maximum drum water silica con-centration is 2.8 ppm. In a 2,400 psi boiler the recommended maximum is 0.21 ppm!

FEAtUrEs

Figure 2. A modern sample panel arrangement. Photo courtesy of Swan Analytical Instruments.


FEAtUrEs

Main and reheat steamMain and reheat steam analyses indicate not only what

impurities exist due to carryover from the boiler water, but also those impurities introduced via spray attemperators. For new units, the primary sampling criteria is cation conductivi-ty, where a common turbine manufacturer limit for warranty issues is ≤0.2 µS/cm.

Recommended analyses include:Core On-Line

• Degassed Cation Conductivity• Sodium

Optional On-Line• Silica

Although silica is shown as an optional parameter, it is the author’s belief that it belongs in the “Core Parameter” category. The recommended limit is ≤10 ppb, and silica in higher con-centrations can precipitate on turbine blades and influence the aerodynamics of the turbine.

Sodium is a measurement that is typically utilized to track mechanical carryover of impurities in the steam.

Automated data evaluationA key to the successful implementation and operation of

chemistry monitoring and chemical feed systems is ensuring that the data is acted upon promptly to prevent chemistry upsets and to keep conditions within proper control parame-ters. A technology is now available (please contact me for more details) that is designed to accept continuous on-line readings and, via algorithms incorporated into the plant distributed control system (DCS), perform several functions. First, a prop-erly designed system will provide continuous, real-time read-outs of system chemistry from the condensate/feedwater sys-tem through the boiler, superheater and into the steam turbine. This data gives operators and technical personnel instantaneous access to complete steam generator conditions.

The system can be configured to immediately alarm plant personnel if any sample exceeds recommended chemistry guide-lines. In many cases, chemistry excursions may be minor and easily correctable. However, some alarms are vital, including:

• If boiler water pH drops below 8.0, immediate unit shutdown is necessary unless an error is discovered in the instrument.

• If condensate pump discharge degassed cation conduc-tivity and sodium sharply rise above normal limits of 0.2 µS/cm and 3 parts-per-billion (ppb), respectively, unit shutdown within four hours might be required. These readings indicate a major condenser tube leak, in which the impurities can rapidly cause hydrogen damage and other corrosion in the steam generator.

• Excursions in main or reheat steam chemistry can indi-cate one of several serious problems, including failed drum moisture separators, excessive firing or poor boiler water chemistry control.

Instrumentation capabilitiesThe revolution in electronics during the last several decades

has not been lost in the analytical chemistry field. Instruments can now detect impurities at extremely low concentrations, and reliability has greatly improved.

Furthermore, many of the instruments, such as those shown in Figure 2, have self-diagnostic capabilities. This can be extremely important. Consider the most critical case, in which unit shutdown is called for if the boiler water pH drops below 8. A self-diagnostic pH meter can inform plant personnel if the readings are valid or incorrect due to an instrument error. Also, in some cases multiple instrument readings can be integrated into chemistry evaluations. For example, if boiler pH begins to rapidly decrease, the primary reason would be cooling water in-leakage at the condenser or malfunction of the makeup water treatment system. If the condensate pump discharge cat-ion conductivity and sodium monitors indicate no contamina-tion, the pH meter is almost certainly in error.

Automated chemical feed controlAs the initial discussion outlined, for utility steam genera-

tors the primary chemical feeds are ammonia or an amine for pH control in the condensate/feedwater system, and tri-sodi-um phosphate (or in some cases caustic) for boiler water pH conditioning. The standard technique for ammonia feed is to calibrate the feed control based on specific conductivity read-ings, which are very straightforward and reliable. Much more complicated is control of the tri-sodium phosphate feed. Drum boilers, by their very nature, “cycle up” impurities, even when they enter in trace amounts. These impurities typically will include chlorides, which can be very detrimental if not prop-erly controlled by chemistry. Furthermore, any ammonia that enters the boiler will influence the pH of cooled samples, but has little effect at the temperatures in the boiler. However, cal-culations have been developed that allow for accurate calcula-tion of system chemistry, and subsequent chemical feed, based on standard on-line readings including, specific and degassed cation conductivity, pH and phosphate concentration. The upshot is that this technology can incorporate chemical feed capabilities into the monitoring and data display functions to provide as much as possible a complete, automated system. ~

Brad Buecker is a process specialist with Kiewit Engineering and Design Company, in Lenexa, Kan. He has more than 33 years of experience in, or affiliated with, the power industry, 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. He has a bachelor’s degree in chemistry from Iowa State University with additional course work in fluid mechanics, materials and energy balances, and advanced inorganic chemistry. He has written many articles and three books on steam generation topics. He also is a member of the ACS, AIChE, ASME, CTI and NACE, as well as being part of the ASME Research Committee on Power Plant & Environmental Chemistry and the program planning committee for the Electric Utility Chemistry Workshop.


Components of electrical machines are subject to thermal, electrical, ambient and mechanical stresses that lead to degrada-tion as materials lose strength over time. Condition monitoring can detect premature failure and extend the life of the machine. Rotating machinery critical to the process chain – including AC/DC motors, turbines, fractional horsepower motors, VFD controllers, SCR controllers and generator exciters – should be continuously monitored to detect impending failures. Energy distribution networks are highly dependent on transformers and failure of equipment or surrounding components can lead to blackouts or catastrophic failures. Any change in machinery performance, including vibration, temperature or current draw should be frequently examined to ensure continuous operation.

Vibration monitoring of crucial equipment can help detect a variety of machinery faults, including looseness, imbal-ance and misalignment. Bearing and lubrication issues can be resolved before causing damage to internal components. Monitoring machinery located in close proximity to wind tur-bine generators or VFD/SCR controllers requires instrumen-tation capable of withstanding high levels of electromagnetic interference (EMI) and electrical fast transients (EFT). High voltage, high electric and magnetic fields can cause strong EMI, vibration sensors mounted in industrial environments should be able to operate without damage or risk of degradation. Rugged design and high performing components ensure reliable opera-tion in harsh industrial environments without communication loss or delays.

Most accelerometers are suitable for hot and humid indus-trial environments, but can fail when exposed to high transient voltages. HV series accelerometers are immune to electrically noisy environments by providing extraordinary EMI and EFT protection and high electrical isolation between the sensor cir-cuitry and the machine.

A material with high electrical resistance and high break-down voltage provides the necessary electrical insulation between the mounting surface and the accelerometer’s case and connector. The sensor casings are a ceramic material much like the type used for insulators on high voltage power lines. Inside the high voltage ceramic outer case, which serves as an isolator, the internal accelerometer is housed in a stainless steel case, providing additional support to the ceramic structure. Internal potting adds additional isolation and improves the frequency response of the sensor, making it comparable to standard sen-sors. Since the majority of vibration sensors use stainless steel outer casings, the new ceramic material was fully tested to ensure equal durability in the field. The sensors passed a 500 lb pull-strength test, confirming the survivability of the potting

and ceramic material under severe stress con-ditions.

Another design con-sideration was shock survivability. The shock limit of a working accelerometer is speci-fied to 2,000 g peak. To demonstrate the strength of the ceramic insula-tor, HV sensors were subjected to a series of shock pulses up to 8,500 g peak through the sen-sitive axes during the development phase. No cracks developed in the ceramic cup, proving its suitability as an industri-al-grade sensor.

Without insulator cups, typical sensors have

Vibration monitoring considerations in high EMI environments

By Shalvi Desai and Renard Klubnik, Meggit Sensing Systems

MAiNtENANCE MAttErs

Figure 1. Internal components

Figure 2. HV accelerometer


a nominal resonance of 30 kHz. The addition of the insulator cup drops the resonance frequency of the HV sensors to 25 kHz. The effect on the frequency response is minimal when making measurements on typical machinery, with no difference in the ±5 percent response within the amplitude range.

Arcing can occur when high potential is separated by a non-conductive material, like in a capacitor, and the breakdown voltage is exceeded. HV sensors are designed with connectors that utilize an ability to withstand high voltage dielectric to prevent arcing between pins and pins to the shell. The new design employs a cup that holds the ceramic insert. A high dielectric potting material between the ceramic cup and stain-less steel cup adds to the overall performance of the sensor.

Testing was conducted to determine the ability to withstand voltage between the accelerometer’s mounting surface and the connector. DC levels up to 6 kV and an AC level of 5 kV were successfully applied between the connector and the accelerom-

eter’s base for a period of one minute. Impedance measurements were made between the connector and base, with the results shown in Table 2.

A protection circuit helps protect against dam-age from EFT and Electro Static Discharge (ESD) events induced through the accelerometer’s cable. ESD events often occur during installation, com-missioning or servicing of monitoring systems. While proper ESD precautions are always recom-mended, the built-in protection circuit can help prevent failures due to transient events. Laboratory testing confirmed that no damage to the sensor occurred when exposed to EFT and surge levels of 6 kV, as well as ESD levels up to 15 kV.

Motors and generators are often located next to or near instrumentation cable trays. EMI and Radio Interference (RFI) can interfere with signal trans-mission causing data errors. These cable runs pro-vide a path with a means to store charge through the wire capacitance. Some monitoring systems might use up to 1,000´ of wire between the sen-sor and data access point. To reduce interference,

shielded cables and connectors should be used with high EMI resistance sensors to ensure reliability of data.

Two primary types of shielding are available for high EMI environments: braided wire or foil shielding. Foil shields are typically used with high frequency signals within electronic cir-cuitry. They can be used in machinery health monitoring appli-cations, but the effectiveness of the shield can be compromised by the strength of the RFI. Foil shields also provide poor isola-tion of low frequency signals, such as ground loop interference.

Braided shields offer up to 95 percent shielding of signal carrying conductors. The wire gauge and tightness of the weave determines the effectiveness of the braided shield. The mass of the braid is higher than a foil shield, offering better conductivi-ty to ground and secure connections at the terminal blocks.

When monitoring vibration in high EMI environments, it is important that sensors output reliable data over time. Monitoring equipment should be able to endure conditions that can include extremely strong electric and magnetic fields. Standard industrial accelerometers can suffer severe failures in such environments. By employing sensors specifically designed with high EMI resistance, failure and replacement can be avoided. Severe interference can cause erroneous data and mis-inform personnel about the true nature of machinery health. Employing long-lasting and durable monitoring solutions helps ensure the reliability of the entire industrial process, maintaining continuous output and eliminating unnecessary downtime. ~

Shalvi Desai is a marketing communication specialist with Meggitt Sensing Systems, www.wilcoxon.com. You may contact her by emailing [email protected]. Renard Klubnik is an application engineer with Meggitt Sensing Systems, www.wilcoxon.com. You may contact him by emailing [email protected].

MAiNtENANCE MAttErs

Figure 3. Types of shielding, braided shield (top) and foil shield (bottom)

Table 1 – Comparison Of Frequency Response Levels

Frequency Range

Amplitude Limits Without Insulator Cup With Insulator Cup

± 5% 3.0 Hz to 5.0 kHz 3.0 Hz to 5.0 kHz

± 10% 1.0 Hz to 9.0 kHz 1.0 Hz to 7.0 kHz

± 3 dB 0.5 Hz to 14.0 kHz 0.5 Hz to 12.0 kHz

Table 2 – Impedance Measurements

Frequency Resistance Between Connector And Base

DC > 10 GΩ

100 Hz > 10 GΩ

1 kHz > 10 MΩ

10 kHz > 1 MΩ

15 ENERGY-TECH.com ASME Power Division Special Section | JANUARY 2015

Justification for long-distance transmission

By Nathan Smith, University of Maryland, Baltimore County, and Alex Pavlak, Future of Energy Initiative

AsME FEAtUrE

IntroductionThe objective of this paper is to determine

if long distance transmission between east coast wind farms (PJM) and Midwest wind farms (MISO) enables standalone wind to have system capacity. More specifically, if PJM and MISO were interconnected, can conventional genera-tion be retired and still maintain pre-connection levels of reliability.

Long distance transmission has been justified on the basis of transmitting power from where it is generated to where it is needed. A much stronger argument could be made if long dis-tance interconnection increased the capacity of a system. Wind can contribute to system capacity in two ways: 1) If standalone wind has capacity when measured by traditional reliability metrics or 2) If the combination of wind with the tradi-tional generators on the grid somehow increases system capacity. In Wind System Reliability and Capacity, Pavlak & Windsor[2] address the latter question. This paper is directed at the former question.

If the wind is always blowing somewhere, then the time series from a standalone wind sys-tem would, with long distance interconnection, never drop to zero and the standalone wind sys-tem would contribute to overall system capacity. If the time series does drop to zero, wind also can contribute to system capacity if it is reliably blowing during peak load. The method used to quantify system capacity is called Effective Load Carrying Capacity.

MethodologyThe methodology used in this paper was

developed in a Power2014 paper by Pavlak & Windsor[3]. Figures 1 & 2 are taken from that paper.

Effective Load Carrying Capacity (ELCC) is a statistical technique that was developed to calculate the capacity of electric power systems.[4] The red curve in Figure 1 above is a Cumulative Distribution Function (DF) of 100 inde-pendent generators. The ELCC is the power level at which the system can be said to have adequate reliability. The adequacy of the reliability is determined by a reliability factor known as the Loss of Load Expectation (LOLE).

A typical LOLE for electrical systems is one-day-in-10-years.[5] This does not correspond to a blackout or system failure, but an inability to satisfy load in which the load would have to be managed some other way, such as demand management or importing power. In dimension-less terms, one-day-in-10-years is equivalent to a LOLE of 1/3,650 or 0.00027 (rounded to 0.0003). Alternatively, this corresponds to a loss of load for 0.0003 * 365 days * 24

Figure 1. Calculating System ELCC

Figure 2. DFs for Standalone Wind Systems


hours/day = 2.6 hours/year. By this metric, any standalone wind system where wind production drops to zero for more than 2.6 hours/year has no system capacity. However, since any wind system has a parasitic electrical load, a more realistic evaluation might be to consider any wind system that drops below 0.5 percent of nameplate for more than 2.6 hours/year to have no system capacity.

Figure 2 shows the DFs calculated for several standalone wind systems; the solid red curve is the reference, the same 100 independent generator system depicted in Figure 1.

The dotted black curve is the DF for a single (Vestas 3 MW) wind farm calculated by assuming Rayleigh wind fluctuations and an average capacity of 0.25. The purple dash-dot curve is the DF for standalone wind on the PJM grid for 2012. The long-dash green curve is the DF for standalone wind on EirGrid for 2012. The boxes are DF data reported by Cox for the British market in 2007.[6]

The DFs for the standalone wind systems (PJM, EirGrid and British grid) are all remarkably similar to each other, but drastically different from the 100 independent genera-tor system. This shows that wind generators must be ana-lyzed differently than classical generators.

The determination of the ELCC comes from the upper left hand corner of Figure 2.

A detailed description of the process used to calculate ELCC is shown and explained in Figure 3.

• Step 1: The hourly wind data for both PJM and MISO regions is imported and put into a suitable format for data analysis.

• Step 2: For the year analyzed (2012), PJM was build-ing new wind farms. In order to correct for this capacity increase, the nameplate of the fall was adjust-ed to have the same nameplate as in the spring as described in the following section. Time zone differ-ences and Daylight Savings Time also were accounted for to ensure the two time series had the correct hours matched.

• Step 3a: The time series were sorted to order the wind production values from greatest to least in order to prepare for the DF calculations. A time series of the sum of PJM and MISO at each given hour was created to simulate a connected system.

• Step 3b: To simulate a statistically independent com-bination, the PJM series was scrambled out of order and then added to the MISO as in step 3a. This was done to simulate a statistically independent combina-tion.

• Step 4: The DFs for the various time series were cal-culated; they are defined by F(x) = P(X < x), which is essentially a way of saying that the function gives the probability that the system power is greater than any given power value. X is a random variable rep-resenting the system power and x are given power values.

• Step 5: The ELCC was determined according to the method described in[4], by simply finding the number of data points above an availability of 0.9997 (See Figure 1).

Interconnected PJM+MISOUsing hourly averaged wind data from 2012,

Cumulative Distribution Functions (DFs) were created for each of the time series (PJM and MISO)[7][8] and the sum-mation of the time series on an hour by hour basis (PJM + MISO). The wind data was given by both ISO for every hour beginning on January 1st at 12:00AM of 2012 and ending on January 1st at 12:00AM of 2013. Inconsistencies due to time zone differences and daylight savings time were accounted for. PJM also was building wind during the year; this was corrected for by identifying the peak wind in the fall and spring and multiplying the spring data by the ratio to ensure it had the same nameplate as the

AsME FEAtUrE

NomenclatureDF – Cumulative Distribution Function. The probability that a system value is greater (or less) than the abscissa.

EirGrid – The Irish national grid.

ELCC – Effective load carrying capacity, a statistical tech-nique for measuring system capacity.

LOLE – Loss of Load Expectation, a reliability criterion, typi-cally one-day-in-ten-years or 0.00027.

MISO – Midcontinent Independent System Operator

PJM – PJM Interconnection, LLC, The largest independent system operator

Figure 3.

JANUARY 2015 | ASME Power Division Special Section ENERGY-TECH.com 17

fall, as an approximation for the increased production. The resulting DFs are shown below in Figure 3.

The black curve is the DF for standalone wind on the PJM grid in 2012, the red curve is the DF for standalone wind on the MISO grid in 2012, and the green curve is the DF for standalone wind on a theoretical interconnected PJM-MISO grid in 2012.

As outlined in Figure 1 in the meth-odology section, the ELCC can be deter-mined by finding the power level where the DF crosses an availability of 0.9997 (corresponding to a LOLE of 0.0003). The determination of the ELCC comes from the upper left hand corner of Figure 3, depicted below in Figure 4.

The DFs for standalone wind are repre-sented in the same manner as in Figure 3 and the black line corresponds to an avail-ability of 0.9997. Ergo, the power (% of nameplate) where these DFs cross this availability are the ELCC values. For this scenario, the ELCC values were determined to be: PJM = 0%, MISO = 0.29%, and PJM + MISO = 0.69% (values given in % of nameplate).

The PJM values include negative system powers since they account for the parasitic electrical loads inherent in wind systems. As the MISO data does not account for these losses, any wind system dropping below 0.5 percent of nameplate for more than 2.6 hours/year will be said to have no capacity. By this metric, both PJM and MISO can be said to have negligible capacity. However, the PJM + MISO interconnected system does have defined system capacity as it only drops below 0.5 percent of nameplate for 2 hours/year (based on 2012 data).

Balanced interconnected PJM+MISOAnother pertinent exercise is balancing the PJM and

MISO data so that they have the same average power. By taking the ratio of the unbalanced averages and multiplying all of the PJM data by the result, the same three time series were reconstructed.

The black curve is the balanced DF for standalone wind on the PJM grid in 2012, the red curve is the balanced DF for standalone wind on the MISO grid in 2012, and the orange curve is the balanced DF for standalone wind on a theoretical interconnected PJM-MISO grid in 2012.

In an identical fashion to the unbalanced DFs, the ELCC values were determined using the upper left hand corner of Figure 5, as depicted below in Figure 6.

The balanced DFs for standalone wind are represent-ed in the same manner as in Figure 5 and the black line corresponds to an availability of 0.9997. Ergo, the power (% of nameplate) where these DFs cross this availability are the ELCC values. For this scenario, the ELCC values

AsME FEAtUrE

2014 ASME Student Paper Competition Winner

A Message from the ChairThe ASME Power Division held its first Student Paper

Competition during the 2014 Conference, attracting more than 25 abstracts that resulted in 8 final papers being presented at the conference, and representing student authors from four different countries. In addition to the rigorous peer review process required by ASME for all technical papers; these student papers, as well as the pre-sentations, were further scrutinized by a Committee of Judges.

The purpose of this competition is to encourage active participation of students in the ASME Power Conference by submitting high quality technical papers on various aspects of the Electric Power Generation Industry. The competition seeks to promote the interaction of future engineers with practicing and experienced engineers and help them establish mentoring and networking links with experts in their areas of interest.

The ASME Power Division and the Student Paper Competition Committee is honored to announce Power2014-32144 “Justification for Long Distance Transmission,” authored by Nathan Smith from the University of Maryland, Baltimore County as the winner of this competition. Smith received a $2,000 cash award and his paper is highlighted in this issue of Energy-Tech for its readers to enjoy.

Justin VossASME Student Paper Session Chair

Figure 4. DFs for PJM, MISO and PJM + MISO


were determined to be: PJM = 0%, MISO = 0.29%, and PJM + MISO = 0.49% (values given in % of nameplate). In the balanced case, the PJM + MISO interconnected has more than 2.6 hours/year in which the power drops below 0.5 percent of nameplate, as do the PJM and MISO time series. As a result, all three cases can be said to have negli-gible system capacity.

A summary of the ELCC values for both scenarios is provided in Table 1.

Statistically independent combination

Pavlak & Winsor[2] showed that the parallel connection of a large number of independent generators results in a system availability that is greater than that of any one generator. It is the statistical independence that makes a difference.

Wind farms are not independent of each other and exhibit cor-

relations with space, time and load. So a pertinent question is whether the MISO and PJM wind farms are indepen-dent of each other.

By scrambling (disordering) the PJM data before sum-ming it with the MISO data, a theoretical data set was created that predicts the behavior of PJM and MISO sup-posing they are independent systems.

The orange curve is the unbalanced, interconnected DF (data as published and seen in Figure 3) and the green curve is the balanced, interconnected DF (as seen in Figure 4). The blue curve is the unbalanced, independent DF and the magenta curve is the balanced, independent DF.

In an identical fashion to the previous sections, we can compute the ELCC for the independent scenarios and analyze the results. The ELCC values were determined using the upper left hand corner of Figure 7, as depicted in Figure 8.

The balanced DFs for standalone wind are represented in the same manner as in Figure 5 and the black line cor-responds to an availability of 0.9997. Ergo, the power (% of nameplate) where these DFs cross this availability are the ELCC values. For this scenario, the ELCC values were determined to be: independent PJM/MISO = 2.04% and independent PJM/MISO (balanced) = 2.22% (values given in % of nameplate).

Both of the ELCC values for the independent scenario are well above the values calculated with the actual PJM and MISO data. This indicates that wind production from MISO and PJM are not independent of each other.

ConclusionsThis paper looked at the value to be derived from the

long distance combination of PJM and MISO wind farms. Specifically, does the combined standalone system offer more capacity than that of the separated systems? Capacity is determined by a reliability criteria of one-day-in-ten-years. By this criteria a standalone wind system has no ELCC if the wind production time series is zero (or negli-gibly small) for more than 2.6 hours per year.

AsME FEAtUrE

Table 1 – Summary of ELCC Values

PJM MISO PJM+MISO

Unbalanced 0.0% 0.29% 0.69%

Balanced 0.0% 0.29% 0.49%

Table 2 – Final Summary of ELCC Values

PJM MISO Interconnected Independent

Unbalanced 0.0% 0.29% 0.69% 2.04%

Balanced 0.0% 0.29% 0.49% 2.22%

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AsME FEAtUrE

PJM wind has no ELCC. Indeed, the number is negative for 8 hours because PJM subtracts parasitic electrical operating load from wind production, resulting in 8 hours of negative net generation.

MISO has an ELCC of ~0.3 percent, but MISO does not subtract parasitic electrical loads. It could well be that after subtracting parasitic loads, standalone MISO ELCC would also be zero.

The long distance interconnection of PJM & MISO wind does increase system ELCC, but only to a level of 0.7 percent. Balancing the system so PJM and MISO are the same average size does not make a significant difference.

Fractional percentages are lost in the noise because MISO, unlike PJM does not subtract parasitic operational electrical loads.

If PJM and MISO wind systems were statistically independent of each other, ELCC would be on the order of 1.5-2.5 percent. This suggests that correlations are significant even at these distances.

From the practical perspective of com-paring system concepts, when ELCC for independent generators are in the range of 90 percent, fractional percentages for standalone wind systems can be ignored as negligible.

Long distance transmission can be justi-fied by the need to move power from point A to point B. Geographic diversity reduces the volatility of cumulative wind produc-tion. This paper shows that long distance transmission does not significantly increase system capacity, (<1 percent) at least for the MISO & PJM ISOs. ~

The authors acknowledge the support of the Future of Energy (FoE) Initiative.

References1. Asari, M., Nanahara, T., Maejima, Yamaguchi, K., Sato,

T., A Study on Smoothing Effect on Output Fluctuation of Distributed Wind Power Generation, 0-7803-7525 IEEE 2002

2. Pavlak, A., Winsor, H., Wind System Reliability and Capacity, Power2014-32148, Proceedings of the ASME 2014 Power Conference (submitted), July 28-31, 2014 Baltimore

3. Pavlak ibid4. Billinton, R., Allan, R.N., Reliability Evaluation of

Power Systems, Plenum Press, 1984.

5. Planning Resource Adequacy Assessment Reliability Standard, US Federal Energy Regulatory Commission, 18 CFR Part 40, [Docket No. RM10-10-1000; Order No. 747] March 17, 2011, available at: http://www.ferc.gov/whats-new/commmeet/2011/031711/E-7.pdf

6. Cox, J., Impact of Intermittency: How Wind Variability could Change the Shape of the British and Irish Electricity 6 Copyright © 2014 by ASME Markets, Fig.5, Poyry, July, 2009, available at:http://www.uwig.org/impactofintermittency.pdf

7. PJM Averaged Hourly Wind Data available at: http://www.pjm.com/markets-and-operations/ops-analysis.aspx

8. MISO Averaged Hourly Wind Data available at: https://www.misoenergy.org/Library/MarketReports/Pages/MarketReports.aspx

Nathan Smith is a first year graduate student working toward his PhD in Materials Science and Engineering at the Pennsylvania State

Figure 6. Balanced DFs for PJM, MISO and PJM + MISO

Figure 5. Calculating System ELCC


AsME FEAtUrE

University. He completed his undergraduate career in 2014 at the University of Maryland, Baltimore County, earning a bachelor’s degree in Physics and Mathematics. In 2012, he began his work in the energy sector with an internship at NIST focused on improving the design and efficiency of Si solar cells. Currently, he is involved with research on recycling rare-earth elements via high temperature electrochemical methods at Penn State. During his senior year at UMBC, he worked with Dr. Pavlak to produce the paper on a theoretical interconnection of wind farms, which he presented at the ASME POWER14 conference. You may contact him by emailing [email protected]. Alex Pavlak, Ph.D., is a professional engineer with 45 years of experience developing a variety of first-of-a-kind systems. He started his career with the Apollo project (master’s thesis), then worked on ballistic missile development for the General Electric Company. In the 1970s he co-founded and became the president of ConSuntrator Inc., a solar collector development company based on patented Solyndra-like optical technology. In the 1980s he led a team that invented and developed a sonar system concept for detecting quiet submarines for the U.S. Navy. In the 1990s he lectured on the use of Modern Tiger Teams for advanced problem solving. He is currently Chairman of the Future of Energy Initiative. His core competencies are systems architecture, energy systems and combining systems engineering with fact-based policy making. He received his PhD in mechanical engineering from Stevens Institute of Technology and is currently a member of INCOSE, IEEE and Sigma Xi. You may contact him by emailing [email protected].

Figure 8. DFs for Independent and Interconnected Systems

Figure 9. ELCC calculation for independent systems

Figure 7. ELCC calculation for balanced DFs


trAiNiNG tiPs

Decades ago, while employed at GE’s Field Engineering Development Center as a technical instructor, I had an opportunity to attend several formal adult educational pro-grams. Two that come to mind are Robert Mager’s seminar on Criterion Referenced Instruction and another seminar at Indiana University.

An internet search can yield numerous results for Criterion Referenced Instruction (CRI). You will learn that the CRI framework is a comprehensive set of methods for the design and delivery of training programs. Some of the critical aspects include:

1. Goal/task analysis – To identify what needs to be learned.

2. Performance objectives – Exact specification of the outcomes to be accomplished and how they are to be evaluated (the criterion).

3. Criterion referenced testing – Evaluation of learn-ing in terms of the knowledge/skills specified in the objectives.

4. Development of learning modules – These should be tied to specific objectives.

Training programs developed in CRI format tend to be self-paced courses involving a variety of different media (e.g., workbooks, videotapes, small group discussions, computer-based instruction). Students learn at their own pace and take tests to determine if they have mastered a module. A course manager also can administer the program and help students with problems.

CRI is based upon the ideas of mas-tery learning and performance-oriented instruction. It also incorporates many of the ideas found in Gagne’s conditions of learning (e.g., task hierarchies, objectives) and is compatible with most theories of adult learning because of the emphasis on learner initiative and self-management.

Fundamentally, one could write an objective that a student shall be able to describe the operation of the AC Lube Oil Pump. Then you could give the stu-dent the turbine-generator OEM manual. Now instruct the student to read tab 12, pages 1-25. In doing so, one would learn the operation of the AC Lube Oil Pump. This points out the importance of item

#4 in the CRI critical aspects, the development of learning modules.

During the adult education seminar at Indiana University, I also learned many different things – but the most signifi-cant was the importance of the training manual. How many times in your career have you picked up a manual and in your reading found a sentence that said “refer to Figure 5”? Then you flip through the pages to finally find Figure 5, and once you find it start thinking, “What was I supposed to be looking for?” You forgot, being distracted as you turned through all the pages to find the figure. Now, unless you put a yellow sticky note in the text that referred to Figure 5, it’s difficult to pick up where you left off. My question is, why do we write a manual and organize the material for the con-venience of the author, or the convenience of the printer, and sacrifice the need of the reader? Hence, we make the suggestion to not interrupt a thought with a page turn. In the 1970s when we first realized this relevance, it was diffi-cult since everything was printed and this meant there would potentially be a lot of partially blank pages. In today’s world, however, with the computer screen, a partially blank screen is

Programmed instructionBy Harold Parker, HPC Technical Services

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no cost (unless you consider the extra ions that are needed to keep the computer screen “on” for a longer period of time).

A couple other relevant items learned at Indiana University were related to the use of graphics that make it easy to understand the topic at hand. Use a simplified pip-ing & instrument diagram to understand the real diagram function. Then use the real diagram to demonstrate how the newly understood principle is applied. Consider Figure 1 as an example. This is a drawing that shows all the major com-ponents making up the lube oil system on a particular gas turbine.

By comparison, wouldn’t you agree that Figure 1 is eas-ier to understand than Figure 2? Figure 1 is used to better understand the actual piping and instrument diagram (we didn’t show one here, but likely you can imagine what the drawing really looks like). By the way, there is likely another dozen simplified drawings that are used to better understand the final piping and instrument drawing.

Now let’s take these two concepts and put them togeth-er to create a well-written programmed instruction – a Learning-Doc, as we call them.

Take a given topic, say the lube oil system on a tur-bine-generator. Now let’s write a set of Learning-Objectives. One (of many) such objective might read: “Describe the purpose of the major components found within this turbine lube oil system.” The objective prior to this might ask the reader to list the major components.

Now, we develop the materials. Seen in Figure 2 is one page of our electronic text describing the lube oil filters, one of the major components in the lube oil system. Notice that a real simple piping & instrument diagram is provided, as well as a photograph of the filters, and text that is describing the filter in question. Also, notice the wasted white space in the lower left corner. We didn’t put any material at this loca-tion since a page turn would likely interrupt the information flow.

There will be more than just one page describing the lube oil filters.

Following this description, we author a “check-your-un-derstanding” question. For example, a high differential pres-sure alarm is typically set to occur at this value.

• 10-psid (69-kPad)• 15-psid (103-kPad)• 20-psid (138-kPad)• 30-psid (206-kPad)

When the reader selects his answer, he/she should be given the opportunity to see the correct answer and some explanation about why the correct answer is correct, or the incorrect answers are wrong, or both. Remember, this check-your-understanding activity is still part of the learning process.

Next, assuming the reader has gotten the correct answer, the reader should be assigned an “on-the-job learning activ-ity.” For example, the reader might be advised to get out the

Figure 1.


trAiNiNG tiPs

OEM piping and instru-ment diagram and locate these filters on that diagram (in our electronic version we suggest a link to auto-matically pull up this dia-gram). The reader might be further advised to go out to the oil tank and physically locate the filters, the transfer valve and the instrumen-tation. It might be further suggested that he/she record the differential pressure. The author should go out of his/her way to emphasize safety and plant procedures when going out to see equipment.

Once this “check-your-understanding” and the “on-the-job learn-ing activity” has been completed, the reader can either take a break or proceed to the next component description making up the lube oil system.

The process continues until the entire document has been completed. The reader studies a “unit of instruction,” takes the quiz, performs an on-the-job activity and proceeds to the next “unit of instruction.” Once complete, a final on-the-job learning activity might be offered, and a final examination should be given.

If you are new to the plant, this learning exercise takes you a few major steps forward to the understanding of the principles of operation of this system. We suggest that after some time passes – maybe a few months, or even a year – the reader should repeat the entire programmed instruction. The reader will learn more depth and should do a more detailed on-the-job learning activity. Let some more time pass and repeat. With each repetition the learner will move forward a few steps. Keep in mind that the reader does not go from “knowing nothing about the topic” to being an “expert” with the completion of study of one document. Instead, the learner takes a few steps forward. If you repeat, you’ll take a few more steps forward. At the end of this series of rep-etitions, along with some practical experience, you might become a ‘course consultant’ that future learners might approach. Interesting enough, in my experience I continue to learn from the questions the new learners ask. Every so often, you will hear something you had never thought of before.

In summary:1. Write good, measurable, learning objectives.2. Break down the technical content into manageable

“units of instruction.”3. Ask “check-your-understanding” questions at the end

of each “unit of instruction.”

4. Offer “on-the-job learning activities,” when applicable, after each “unit of instruction.”

5. Offer a realistic final examination.

You also might be prepared for a lot of work. You will likely find, as an author, there are a lot of things you have not thought about before you started. This means a lot of research. After decades of experience as we’ve written electronic programmed instruction on gas turbines, com-bined-cycle, fossil and nuclear steam turbines and generators, we have found this to be true of every system we’ve worked on. ~

Harold Parker started work in 1969 as a field engineer for GE in Detroit, Mich. He later became a GE start-up engineer, responsible for commissioning new turbine-generators and resolving operational problems as they occurred. In the mid-1970s he became a training specialist and then a training manager, responsible for training new and experienced engineers. Today, he is part owner of HPC Technical Services, www.hpcnet.com, and continues to implement ADDIE training programs in the power generation industry. You may contact him by e-mailing [email protected].

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