June 2015

Bloch Talks Pumps 6 • Successful Condenser Leak Detection 10 • EPA On Ash 12

ENERGY-TECH

JUNE 2015

A WoodwardBizMedia Publication

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Dedicated to the Engineering, Operations & Maintenance of Electric Power Plants In Association with the ASME Power Division

ASME: Wind system reliability and capacity

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FEATURES

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By Heinz P. Bloch, P.E.

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June 2015

Four tips to create a successful condenser leak detection program

By Kim Massey, Day & Zimmermann

COLUMNS

12

Regulations Compliance

Regulations for the management of coal combustion residuals generated by electric utilities

By Mathy Stanislaus, U.S. Environmental Protection Agency

18

Mr. Megawatt

Blowing bellows

By Frank Todd, True North Consulting

28

Editorial views expressed within do not necessarily reflect those of Energy-Tech magazine or WoodwardBizMedia.

Advertising Sales Executives Tim Koehler – tkoehler@WoodwardBizMedia.com Joan Gross – jgross@WoodwardBizMedia.com Thea Somers – thea.somers@WoodwardBizMedia.com

Lubrication options for modern API-610 compliant vertical pumps

Turbine Tech

Crossing the retirement finish line with high temperature steam turbine rotors

By Stephen R. Reid, P.E., and Rachel Sweigart, TG Advisers Inc.

ASME FEATURE

21

Wind system reliability and capacity

By Alex Pavlak and Harry V. Winsor, Future of Energy Initiative

INDUSTRY NOTES

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Editor’s Note and Calendar Advertisers’ Index Energy-Tech Showcase

ON THE WEB Don’t miss Energy-Tech University’s upcoming Summer School series in June, July and August. Join Tom Davis as he explains the maintenance basics you need to keep your plant running. Visit www.energy-tech.com/summerschool for more information.

Cover image © 2015 Ingram Image Ltd.

ENERGY-TECH.com

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EDITOR’S NOTE

June is a month for learning Energy-Tech University and ASME offer opportunities

Have you heard about Energy-Tech University’s Summer School program, starting on June 10-11, and continuing in July and August?

Are you tired of me writing about it, posting it to Facebook and sending emails at least once a week?

I’d apologize, but it’s that important to me that you know about this fantastic training opportunity. Three, two-day courses over three months. Sign up for one, two or all three of them, with the potential of earning 12 PDH credits without having to travel anywhere. No delayed flights. No hotel beds.You can still make dinner with friends or that Little League game. We want to make this easy for you.

Our summer instructor, Tom Davis, is geared up and ready to go too, and I know our attendees will enjoy his teaching style and depth of knowledge on each topic. It’s going to be a great experience and I can’t wait to get started – visit www.energy-tech.com/summerschool for more information. There’s still time to sign up, I hope you can join us.

And, while we’re still on the training/learning topic – are you going to the 2015 ASME Power & Energy Conference in San Diego, Calif.?

Are you presenting a paper? If so, let me know. Energy-Tech will be there and we always enjoy meeting readers and hearing their ideas for the magazine.

This year’s conference will be quite a bit different, since it is combining several of the energy divisions at ASME, but I think it will result in a very dynamic group of people and ideas. I always say that one of my favorite parts of the ASME conference is seeing the exchange of ideas, and I think this year’s conference will definitely enhance that experience.

And whether you sign up for Summer School, attend the ASME Power & Energy Conference or even do both – you have a wealth of training options to fit what works best for your schedule this summer.

I look forward to seeing you – thanks for reading Energy-Tech.

Andrea Hauser

CALENDAR June 10-11, 2015 Energy-Tech University Summer School Online Course: Bearing Installation, Precision Fitting and Lubrication, with Tom Davis www.energy-tech.com/summerschool June 15-19, 2015 Rotor Dynamics and Modeling (RDM) Syria, Va. www.vi-institute.org June 28-July 2, 2015 ASME Power & Energy 2015 San Diego, Calif. www.asmeconferences.org/powerenergy2015 July 8-9, 2015 Energy-Tech University Summer School Online Course: Belt Drives – Installation, Precision Fitting and Lubrication, with Tom Davis www.energy-tech.com/summerschool Aug. 4-6, 2015 Excel I Webinar Course www.energy-tech.com/excel Aug. 12-13, 2015 Energy-Tech University Summer School Online Course: Troubleshooting and Correcting Problems with Rotating Equipment Using Predictive Maintenance Tools, with Tom Davis www.energy-tech.com/summerschool Aug. 18-20, 2015 Excel II Webinar Course www.energy-tech.com/excel Sept. 15-17, 2015 Steam and Gas Turbine Fundamentals www.energy-tech.com/turbines Sept. 21-25, 2015 Machinery Vibration Analysis (MVA) Salem, Mass. www.vi-institute.org Sept. 22-24, 2015 Advanced Turbine Troubleshooting & Failure Prevention www.energy-tech.com/turbines

Submit your events by emailing editorial@woodwardbizmedia.com.

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June 2015

Upcoming webinars and Energy-Tech University Summer School Don’t miss these upcoming training opportunities available exclusively from Energy-Tech!

Sign up today for Early Bird pricing! Group discounts also available!

June 10-11 ETU Summer School: Bearing Installation, Precision Fitting and Lubrication Tom Davis, Maintenance Troubleshooting

The course will be held from noon to 2 p.m. CT each day and attendees will receive 4 PDH credit hours. Register at www.energy-tech.com/summerschool July 8-9 ETU Summer School: Belt Drives – Installation, Maintenance and Troubleshooting

Aug. 12-13 ETU Summer School: Troubleshooting and Correcting Problems with Rotating Equipment Using Predictive Maintenance Tools Tom Davis, Maintenance Troubleshooting

The course will be held from noon to 2 p.m. CT each day and attendees will receive 4 PDH credit hours. Register at www.energy-tech.com/summerschool Aug. 18-20 Excel II Webinar Course Register at www.energy-tech.com/excel

Tom Davis, Maintenance Troubleshooting

The course will be held from noon to 2 p.m. CT each day and attendees will receive 4 PDH credit hours. Register at www.energy-tech.com/summerschool Aug. 4-6 Excel I Webinar Course Register at www.energy-tech.com/excel

Visit our extensive webinar archive at

www.energy-tech.com/etu

Sept. 15-17 Steam and Gas Turbine Fundamentals – Webinar Series Sept. 22-24 Advanced Turbine Troubleshooting & Failure Prevention These intensive, 6-hour courses describe major failure modes that turbines experience. The fundamentals of steam and gas turbine design are covered in detail. In addition, predictive maintenance technologies and associated performance issues are discussed along with case studies that demonstrate turbine fundamentals. Register at www.energy-tech.com/turbines

Ask us about webinar sponsorship opportunities today! www.energy-tech.com • 800.977.0474 • editorial@WoodwardBizMedia.com

FEATURES

Lubrication options for modern API-610 compliant vertical pumps

By Heinz P. Bloch, P.E.

Although vertical pumps are ideally suited for multistage or tapered roller bearings, which might have less than (high differential pressure) services, many vertical pumps are 16,000-hour life at worst conditions to avoid skidding of single stage design. They incorporate an end suction “back in normal operation. In such cases, the vendor must pull out”-type casing, with the hydraulic end being mountstate the shorter design life in the proposal. ed below the liquid level. The impeller is connected to the • For vertical motors and right-angle gears, the thrust motor by means of an extended shaft; the shaft is housed and bearing must be in the non-drive end and will limit supported in a rigid tubular intermediate pipe. axial float to 125 μm (0.005˝).

As a rule, vertical pumps in important hydrocarbon pro• Thrust bearings will be designed to carry the maximum thrust that the pump can develop while starting, cessing services are designed to the requirements found in stopping or operating at any flow rate. an API (American Petroleum Institute) Standard – API-610.

• Hydrodynamic thrust bearings must be selected at no User-purchasers view adherence to the standard’s stipulations more than 50 percent of the bearing manufacturer’s as a powerful risk reduction step. API-compliant equipment rating at twice the pump internal clearances specified incorporates considerable experience-based content derived elsewhere in the pump standard. from reliability-focused users. While equipment cost is always a concern, the best companies aim for proper balance More detailed guidelines on bearings are found in the between initial monetary outlay and long-term reliability. same standard, API-610. As general examples, a number of As a rule, life-cycle cost studies show significant advantages additional bearing-related items are worthy of note: for API-compliant pumps compared to their lower-priced • Each shaft shall be supported by two radial bearings and non-API competitors. An API pumps generally higher relione double-acting axial (thrust) ability will translate to reduced bearing that might or might catastrophic failure risk, and Learn more about bearings such reductions are naturally not be combined with one of with Tom Davis during our first of interest to a multitude of the radial bearings. Bearings industries. shall be one of the following Summer School course, June 10-11. arrangements: rolling-element For more information, visit radial and thrust; hydrodynamAPI 610 highlights www.energy-tech.com/summer school ic radial and rolling-element Special attention is given to thrust; hydrodynamic radial and bearings in the drive systems thrust. of vertical pumps. Regardless • Thrust bearings shall be sized for continuous operation of feasible bearing options, these bearings must always be under all specified conditions, including maximum difdesigned for prevailing radial and/or axial loads. These loads, ferential pressure, and comply with the following: of course, are transmitted from the hydraulic end of the ›› All loads shall be determined at design internal pump and API-610 makes clear that bearings must meet a clearances and also at twice design internal clearnumber of requirements: ances.

• Rolling element bearings will be selected to give a ›› Thrust forces for flexible metal-element couplings basic rating life, in accordance with ISO 281, equivalent shall be calculated on the basis of the maximum to at least 25,000 hours with continuous operation at allowable deflection permitted by the coupling pump rated conditions. manufacturer.

• Rolling element bearings will be selected to give a ›› A sleeve-bearing motor (without a thrust bearing) basic rating life equivalent to at least 16,000 hours is directly connected to the pump shaft with a when carrying the maximum loads (radial or axial or coupling, the coupling-transmitted thrust shall be both) imposed with internal pump clearances at twice assumed to be the maximum motor thrust. the design values, and when operating at any point • Single-row, deep-groove ball bearings will have radial between minimum continuous stable flow and rated internal clearance in accordance with ISO 5753, i.e., flow. larger than “Normal” internal clearance.

• Concessions are made for vertical motors 750 kW (1,000 HP) and larger that are equipped with spherical 6 ENERGY-TECH.com

June 2015

FEATURES • Single- or double-row bearings will not have filling slots.

• In addition to thrust from the rotor and any internal gear reactions due to the most extreme allowable conditions, the axial force transmitted through flexible couplings will be considered a part of the duty of any thrust bearing.

• Thrust bearings will provide fullload capabilities if the pump’s normal direction of rotation is reversed.

• Ball thrust bearings will be of the paired, single-row, 40 degree (0.7 radian) angular contact type (7000-series) with machined brass cages. Non-metallic cages shall not be used (we disagree – see below).

Pressed steel cages may be used if approved by the purchaser. Unless otherwise specified, bearings shall be mounted in a paired arrangement installed back-to-back. The need for bearing clearance or preload will be determined by the vendor to suit the application and meet the bearing life requirements of this International Standard.

Figure 1. Oil-lubricated thrust bearing at drive end of a modern vertical pump with rotating components highlighted in green; cooling water entry is designated as “ER.” Liquid oil is fed from the sump (bottom) to the top of the double-row thrust bearing. (Source: Egger Pumps, Cressier, NE, Switzerland)

Experienced professionals realize, however, that in certain applications an alternative bearing arrangement will prove superior. This is because massive machined bronze cages tend to promote smearing.

Smearing (or skidding) is often noted where bearings operate continuously with minimal axial loads. If loads exceed the capability of paired, angular-contact bearings, alternative rolling-element arrangements may be proposed.

Pump specialists note that sub-clauses apply to all rolling-element bearings, including both ball and roller types.

However, for certain roller bearings (such as cylindrical roller types with separable races) bearing-housing diametric clearance might not be appropriate.

Rolling-element bearings will be located, retained and mounted in accordance with the following: ›› Bearings will be retained on the shaft with an interference fit (usually in the vicinity of 0.0003˝ to 0.0007˝) and fitted into the housing with a diametric clearance, both in accordance with June 2015 ENERGY-TECH.com

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FEATURES ANSI/ABMA 7 (usually ranging from 0.0005˝ to 0.0012˝). ›› Bearings will be mounted directly on the shaft.

Bearing carriers are acceptable only with purchaser approval. ›› Bearings will be located on the shaft using shoulders, collars or other positive locating devices. Snap rings and spring-type washers are not acceptable.

›› The device used to lock thrust bearings to shafts will be restricted to a nut with a tongue-type lock washer.

Vertically suspended pump-driver combinations Thrust bearings that are integral with the driver are addressed in the same API Standard, API-610. The manufacturer must pay attention to the need of adjusting pump rotors in the axial direction. To allow axial rotor adjustment and oil lubrication, the thrust bearing are mounted with an interference fit on a slide-fit, key-driven sleeve.

Designs that tolerate a certain amount of solids typically incorporate fully recessed, vortex flow impellers with rear mounting shroud, incorporating integrally cast back balancing vanes. This design is suitable for handling free-flowing slurries and sludge.

In fact, the impeller design is capable of handling solids up to the diameter of the discharge port. In a leading design offered by a Swiss pump manufacturer, a suction strainer fitted to protect the spark arrestor used in explosion-proof designs limits the practical solid size.

Figure 2. Oil mist-lubricated vertical pump thrust bearing. The oil mist enters at the upper right. After passing through this back-to-back set of bearings, coalesced oil droplets or “excess oil mist” exit from one of the two drain ports. (Source: Afton Pumps, Houston, Texas)

Special design combinations Zone Zero pumps are required in continuously flammable atmospheres.

The casing of one such pump is unique since it employs an internal helical contour that contributes to improved hydraulic efficiency without impeding free passage. Superior products often facilitate maintenance by using step-machined mating face designs, also known as “rabbeted fits.” Thus, when the pump is being re-assembled, it is totally selfaligned.

Recessed impellers are available for many kinds of slurry pumps. Impellers are usually located on the shaft by a parallel key and fixed into position with an impeller screw and washer. Many excellent vertical pumps incorporate a large sole plate (pit cover) allowing the unit to be mounted on top of a tank. The discharge pipe passes through the sole plate and is held in position by means of a weld neck flange; this flange is bolted to the sole plate. A loose discharge flange is often provided that facilitates

Figure 3. Oil-lubricated vertical pump thrust bearing. (Source: Afton Pumps, Houston, Texas)

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June 2015

FEATURES and simplifies the matching of the pump discharge pipe to the customer’s pipe work.

The safety regulations for Zone Zero pumps require provision of a “minimum flow” bypass. In some well-proven designs, the bypass pipe is connected from the discharge pipe and directed through the sole plate back into the tank. Two minimum liquid level probes are often mounted into the sole plate; one is for monitoring the liquid level in the tank and the other for monitoring the liquid level in the column pipe.

Each represents an explosion-proof enclosure.

On Zero-Zero pumps, and as an additional safety feature, the discharge pipe from the cover plate is fitted with a spark arrestor. Ball valves are fitted on either side of the arrestor. ISO-compliant pumps are usually provided with a single mechanical shaft seal (conforming to DIN 24960 dimensions) behind the impeller. The seal is mounted on a replaceable shaft sleeve or in a readily replaceable cartridge. A bottom journal bearing is fitted; it, too is mounted on a separate replaceable shaft sleeve or in a unitized assembly called a cartridge.

When the pump length dictates, intermediate bearings are employed and located between the flange joints of the intermediate pipes. As with the bottom journal bearing, intermediate bearings are mounted on separate replaceable shaft sleeves. The intermediate column pipe is filled with oil; this liquid column provides lubrication to the journal bearings and also encases the drive shaft of superior pump designs.

More vertical pump design characteristics When the pump length dictates, more than one drive shaft may have to be threaded into each other to achieve the needed length between shaft coupling and impeller. Also, two or more sections are then connected by intermediate flanges.

To prevent fluid traveling up the shaft, many vertical pump models incorporate a simple disc that acts as a “liquid thrower.” At the drive shaft end, the shaft is located by two angular contact ball bearings. (Figure 1) The motor is mounted above the sole plate via a motor stand. This stand also has locating registers to guarantee correct alignment of both motor and pump shaft ends. Access to the spark-proof flexible coupling is from opposite sides.

These access points are provided with guards so that when the machine is in operation, no rotating part is exposed.

Motors can be either a metric frame or NEMA frame, flange mounted. ~ Heinz P. Bloch resides in Westminster, Colo. His professional career began in 1962 and included long-term assignments as Exxon Chemical’s regional machinery specialist for the U.S. He has authored more than 600 publications, among them 19 comprehensive books on practical machinery management, failure analysis, failure avoidance, compressors, steam turbines, pumps, oil-mist lubrication and practical lubrication for industry. Bloch holds bachelor’s and master’s degrees in mechanical engineering. He is an ASME Life Fellow and maintains registration as a Professional Engineer in New Jersey and Texas. You may contact him by emailing editorial@woodwardbizmedia.com.

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June 2015 ENERGY-TECH.com

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FEATURES

Four tips to create a successful condenser leak detection program

By Kim Massey, Day & Zimmermann

Without regular maintenance and repairs, condenser tube leaks and condenser air inleakage can turn into costly problems for power plant managers. A large leak can lead to unplanned outages that last multiple days and result in millions of dollars in lost income. Despite the risks, managers consistently wrestle with the decision of when a leak is of high concern and when repairs can be reasonably delayed. As long as a unit is running there is hesitancy to address leaks that would result in downtime.

Ultimately, each identified leak must be evaluated on a case-by-case basis, but what’s concerning is that some plants don’t have the proper systems and processes in place to check regularly for leaks. While a comprehensive leak detection plan won’t eliminate all potential issues, developing one with your internal teams and a maintenance partner can go a long way toward increasing efficiency and protecting against major disruption and damages. Below are four tips for building an effective leak detection program.

Have a proactive plan A common approach to scheduling condenser inspections is to sync them up with planned outages. It’s a way to make sure that inspections happen regularly and also allows plant managers to address potential issues without interrupting normal operations. While this plan seems sensible on its face, some

plants don’t have yearly outages. Nuclear units for instance are on 18- to 20-month outage cycles. Waiting nearly two years in between inspections might be too long to prevent minor issues from becoming major ones.

Plant managers need to consider a more aggressive and proactive approach to tackling leak detection programs. At minimum, condensers should be checked twice a year. Optimally, a quarterly program will eliminate many of the risks associated with leaks. While there can be a cost associated with these inspections, they are far less of a cost burden than a major leak that leads to an unplanned outage. They also can lead to considerable cost savings by improving condenser efficiency.

Beware of hidden leaks There are a number of areas within a condenser unit in which leaks are extremely common. Most leak detection programs rightfully prioritize inspecting these areas. Unfortunately, the nature of leaks makes their location unpredictable and some leaks can be hard to find without extensive experience in inspection methodologies. Condenser inspection is arduous and intense work. Every condenser has dark, hot crevices that maintenance personnel might be hesitant to inspect. When inspections skim these areas instead of doing a thorough check, plant managers expose themselves to greater risk.

Among the more uncommon areas where leaks have been identified are at gland steam exhausters, oil-bearing drains, on the turbine shell and at the base of a condenser. When working with maintenance partners and leak detection teams, plant managers should ask for a comprehensive checklist of the areas that were inspected and a detailed list of test results. Even if the probability of leaks in each of these areas remains low, they should still be on the list.

Sweat the small stuff Even with regular and thorough inspections and repairs, it’s almost a guarantee that every condenser in the world has a leak right now.

Some leaks might be small and are unlikely to get bigger. But others will start small only to grow into

Figure 1. Air inleakage testing. Contributed by Day & Zimmermann.

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FEATURES in Norfolk, Va. In addition to directing and managing the overall much larger leaks. An effective leak detection partner should operation of Condenser Services Division, including international be able to explain the risk factors based on the location and operations, Massey is also responsible for long-range strategic nature of identified leaks. But placing leaks on a risk scale planning, sales, and operational forecasting to achieve profitable can give plant managers a false sense of security. There’s no growth. Having been with Day & Zimmermann for more than 30 years, Massey has held various positions within the company, such thing as a low-risk leak. To maintain operational effiincluding project and personnel management, product development, ciency, every leak is important. field operations, customer relations, proposal preparation and While the primary focus should be to repair larger leaks, contract negotiations and scheduling. You may email Massey at plant managers cannot stop there. Small to moderate-sized editorial@woodwardbizmedia.com. leaks also can result in hundreds of thousands of dollars in additional fuel costs per year. Additionally, condensers with multiple smaller leaks can result in a loss of generating capacity, higher chemical or treatment costs or increased emissions resulting in regulatory concerns.

Y O U R C O M P L E T E S O U R C E F O R P R O C E S S B A L L V A LV E S Different types of condensers also are much more susceptible to inefficiencies than others. For instance, it doesn’t take many leaks ™ to cause an issue for an air cooled condenser. These types of condensers need to be more closely monitored.

• 2- piece, 3-piece, multi-port, sanitary, flanged, Direct Actuator Mount Plant managers should carefully consider Ball Valves thru 12” full port repairing small to moderate leaks even if • API-607 Firesafe condensers continue to run without repairs.

With tight margins at most power plants, • TA-LUFT environmentally friendly stem packing design repair costs are a concern, but small leaks • FM-Approved Safety Shut-off Ball Valves have smaller price tags than large leaks.

• Metal Seat, High Temperature

Customize your strategy Every plant is different and every plant manager has their own set of unique challenges in ensuring operational efficiency.

Condenser leak detection is only one aspect of an overarching maintenance plan.

Understanding how it fits into that larger maintenance strategy allows managers to set aside the proper resources for plan execution.

It’s critical that plants identify maintenance partners that allow for flexibility in how they execute work and attack repairs.

The choice to make a repair is in the hands of the plant manager and true maintenance partners should be working with managers to find the best solutions that consider both condenser efficiency and overall plant spend.

This requires a trusted source of information that has a track record of both technical proficiency and business acumen. Working with these types of partners, plant managers will be more likely to create a truly custom strategy that keeps condensers running efficiently and effectively. ~

• V-port and segment control valves • Direct mount Electric and Pneumatic Actuation Packages • Numerous Seat Materials • Carbon, Stainless and special alloys

9955 International Boulevard Cincinnati, Ohio 45246

Kim Massey is vice president of Condenser Services at Day & Zimmermann, with offices

(513) 247-5465 FAX (513) 247-5462 sales@atcontrols.com www.atcontrols.com

In stock for immediate shipment - The right valve, right now!

June 2015 ENERGY-TECH.com

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REGULATIONS COMPLIANCE

Regulations for the management of coal combustion residuals generated by electric utilities

By Mathy Stanislaus, U.S. Environmental Protection Agency

The U.S. Environmental Protection Agency (EPA) recently finalized regulations that establish comprehensive requirements for the disposal of coal combustion residuals (CCR or coal ash) as solid waste (non-hazardous waste) under Subtitle D of the Resource Conservation and Recovery Act (RCRA). These regulations provide water and air protections for communities near coal-fired power plants, and require these facilities to provide communities with the information they need to determine if facilities are in compliance with the regulations.

EPA’s risk assessment presents a static snapshot of CCR disposal practices at the time. While newer disposal units might be managed in a more protective manner, older units, which still comprise the majority of current units, continue to operate in a manner that poses risks to human health and the environment.

Damages from the mismanagement of CCR The EPA has a long history of considering damage cases in its regulatory decisions under RCRA. Damage cases provide evidence of both the extent and nature of the potential risks Generation, chemistry and management of coal to human health and the environment. The number of damage cases collected for this rulemaking was 157, and is the largest combustion residuals number of documented damage cases in the history of the CCR is one of the largest industrial wastes generated in RCRA program.[4] the United States. In 2012, more than 470 coal-fired electric Damages typically consist of contaminants of concern (arseutilities in 47 states and Puerto Rico generated approximately nic, selenium, boron, sulfate, 110 million tons of CCR.[1] CCR includes fly ash, bottom An existing CCR unit is one that receives CCR etc.) exceeding a drinking water standard in groundwater ash, boiler slag and flue gas both before and after the effective date of the or exceeding primary water desulfurization materials.[2] quality criteria in surface The contaminants in CCR of rule, or for which construction commenced water, or a catastrophic failure most environmental concern prior to the effective date of the rule and of a surface impoundment are antimony, arsenic, barium, receives CCR on or after the effective date that could impact groundberyllium, cadmium, chrowater or surface water. These mium, lead, mercury, nickel, of the rule. A new CCR unit is one that first damage cases were primarily selenium, silver and thallium receives CCR or commences construction associated with unlined units because of the mobility of after the effective date of the rule. and were most frequently metals and the large size associated with releases of of disposal units. In 2012, arsenic. approximately 40 percent of generated CCR was beneficially Recent CCR surface impoundment failures include the used (e.g., in concrete or wallboard), with the remaining 60 percatastrophic failure of an impoundment dike at TVA’s Kingston cent disposed of in surface impoundments and landfills (CCR Plant in Harriman, Tenn., on Dec. 22, 2008. This failure led to disposal units). CCR disposal currently occurs at more than 310 the release of approximately 5.4 million cubic yards of fly ash active on-site landfills, and at more than 735 active on-site sursludge over an approximately 300-acre area and into a branch of face impoundments. the Emory River (Figures 1 and 2).[5,6] The ash slide disrupted power, ruptured a gas line, knocked one home off its foundaRisks to human health and the environment Based on risk analyses conducted for the final rule, EPA con- tion and damaged others (Figure 3). Another case involved the structural failure of an inactive surface impoundment at Duke cluded that disposal of CCR in unlined surface impoundments Energy’s Dan River Steam Station in Eden, N.C., on Feb. 2, and landfills presents the greatest risks to human health and the 2014, which led to the release of between 50,000 and 82,000 environment. As modeled, the national risks from clay-lined tons of coal ash and slurry into the Dan River, about 80 miles units are lower than those for unlined units, but such units can exceed risk criteria at individual sites. Composite liners were the upstream from the Kerr Reservoir (Figure 4). The cause of the failure was the collapse of a concrete and corrugated metal only liner type modeled that effectively reduced risks from all storm water discharge pipe that passed underneath the interior pathways and constituents far below human health and ecologiof the CCR surface impoundment.[7] cal criteria in every sensitivity analysis conducted.

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REGULATIONS COMPLIANCE

Figures 1a, 1b and 1c. TVA Kingston Plant CCR Surface Impoundment

The majority of the EPA’s documented record of confirmed damage cases are from wet handling, treatment and disposal in surface impoundments, cooling ponds and artificial wetlands that constitute nearly half of the total number of implicated CCR disposal units. In comparison, dry handling and disposal in landfills, sand and gravel pits, storage piles, and certain structural fills account for about one-third of the confirmed damage cases.

Minimum national criteria for CCR landfills and CCR surface impoundments Both the risks posed by current CCR management practices as shown in EPA’s risk assessment, and the overwhelming number of documented damage cases, compelled EPA to finalize minimum national criteria for CCR landfills, CCR surface impoundments, and all lateral expansions of CCR units to protect human health and the environment. These criteria include: • location restrictions • liner design criteria • structural integrity requirements • requirements to minimize fugitive dust • groundwater monitoring and corrective action requirements • closure and post-closure care requirements • recordkeeping, notification and Internet posting requirements

Figure 2. TVA Kingston Plant Fly Ash Spill

These criteria are summarized below and Table 1 details the scope of the regulations.

Location restrictions The location criteria include restrictions on the placement of CCR above the uppermost aquifer, in wetlands, within fault areas, in seismic impact zones and in unstable areas. All of these restrictions require the owner or operator of a CCR disposal unit to demonstrate that they meet the specific criteria. The five location restrictions apply to all new CCR landfills, all new and existing CCR surface impoundments, and all lateral expansions

Figure 3. Damage to House from TVA Kingston Plant Fly Ash Spill.

Credit: Tennessee Valley Authority.

of CCR units. Existing CCR landfills are only subject to the location restriction for unstable areas. Units that do not meet these restrictions can retrofit and make appropriate engineering demonstrations so that the unit meets the criteria. Owners or operators of existing CCR units that cannot make the required demonstrations must close the units, while owners or operators

June 2015 ENERGY-TECH.com

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REGULATIONS COMPLIANCE

Figure 4. A concrete pipe below this impoundment failed, releasing coal ash and ash pond water into the Dan River. Credit; UFWS/ Steven Alexander.

of new CCR units and all lateral expansions who fail to make the required demonstrations are prohibited from placing CCR in the CCR unit.

Liner requirements The rule also establishes liner design standards to help prevent contaminants in CCR from leaching out of the CCR unit

and contaminating groundwater. All new CCR landfills, new CCR surface impoundments, and lateral expansions of CCR units must be lined with a composite liner (see sidebar). The rule allows an owner or operator to construct a new CCR unit with an alternative composite liner, provided the alternative composite liner performs no less effectively than a composite liner with two feet of compacted soil. New landfills also are required to operate with a leachate collection and removal system, designed to remove excess leachate that might accumulate on top of the composite (or alternative

composite) liner.

Existing CCR units can continue to receive CCR after the effective date of the rule without retrofitting with a composite or alternative composite liner; however, these units must meet all applicable groundwater monitoring and corrective action criteria to address any groundwater releases

Table 1 – Applicability of the CCR Rule The rule applies to:

The rule does not apply to:

New and existing CCR landfills and surface impoundments, including any lateral expansions of such units that dispose of or otherwise engage in solid waste management of CCR generated from the combustion of coal at electric utilities and independent power producers.

CCR landfills that have ceased receiving CCR prior to the effective date of the rule (six months after publication in the Federal Register).

CCR disposal units located off-site of the electric utility or independent power producer.

CCR generated at non-utility power producers such as hospitals, universities and manufacturing facilities that produce electricity primarily for their own use.

CCR disposal units at “active” electric utilities and independent power producers; i.e., those that generate electricity, regardless of the fuel currently used to produce electricity.

Electric utilities or independent power producers that have ceased producing electricity prior to the effective date of the rule.

“Inactive” CCR surface impoundments at any active electric utilities or independent power producers, regardless of the fuel currently being used to produce electricity; i.e., surface impoundments at any active electric utility or independent power producer that have ceased receiving CCR or otherwise actively managing CCR.

CCR placement at active or abandoned underground or surface coal mines.

Municipal solid waste landfills that receive CCR for disposal or for daily cover.

Practices that meet the definition of a beneficial use of CCR.

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June 2015

REGULATIONS COMPLIANCE promptly. Existing CCR surface impoundments not constructed with either (1) a composite liner, (2) an alternative composite liner or (3) at least two feet of compacted soil with a hydraulic conductivity of 1 x 10-7 centimeters per second, must retrofit or close. Moreover, if an existing CCR surface impoundment constructed with one of these three liner types detects concentrations of one or more constituents listed in Table 2 at statistically significant levels above the groundwater protection standard established by the rule, the CCR unit must retrofit or close.

Groundwater monitoring requirements The groundwater monitoring and corrective action criteria require an owner or operator of a CCR unit to install a system of monitoring wells, and specify procedures for sampling these wells and methods for analyzing the groundwater data collected to detect the presence of potentially toxic constituents (e.g., metals) and other monitoring parameters (e.g., pH, total dissolved solids) released from the units. The rule establishes a groundwater monitoring program consisting of detection monitoring, assessment monitoring and corrective action.

If the groundwater monitoring program demonstrates an excess of a drinking water standard for any identified constituents in CCR (Table 2), the owner or operator must initiate corrective action.

Table 2 – Constituents For Assessment Monitoring Antimony

Chromium

Mercury

Arsenic

Cobalt

Molybdenum

Barium

Fluoride

Selenium

Beryllium

Lead

Thallium

Cadmium

Lithium

Radium 226 and 228 combined

Fugitive dust requirements The fugitive dust criteria in this rule address the pollution caused by windblown dust from CCR units. Owners or operators of a CCR disposal unit must adopt measures that will effectively minimize airborne CCR at the facility, including fugitive dust originating from CCR units, CCR piles, roads and other CCR management activities. The rule also requires documentation of the measures taken to comply with the technical standard in a “CCR fugitive dust control plan.” In the plan, owners or operators are required to document the applicable and appropriate activities for the conditions at the facility that will minimize airborne CCR at the facility, such as wet conditioning of CCR.

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REGULATIONS COMPLIANCE action plan that defines the events and circumstances involving Structural integrity and inspection requirements the CCR unit that represent a safety emergency and identify To help prevent the damages associated with structural the actions that will be taken in the event of a safety emergency. failures of CCR surface impoundments, the final rule estabOwners or operators of all CCR surface impoundments lishes structural integrity criteria for new and existing surface also are required to conduct weekly inspections by a qualified impoundments and all lateral expansions. While the applicability person to detect, as early as of the structural integrity practicable, signs of distress requirements to individual A composite liner consists of two in the unit that might result CCR surface impoundments components: a geomembrane upper in larger, more severe convaries depending on factors ditions. Monitoring of all such as dike heights and the component and a two-foot layer of instrumentation supporting hazard potential (potential compacted soil with a hydraulic conductivity the operation of the CCR for loss of life, environmental of 1 x 10-7 centimeters per second, lower unit, conducted by a qualidamage and economic loss fied person no less than once if there is a dike failure) of component. Both components must be per month is also required. the unit, the rule establishinstalled in direct and uniform contact with Owners or operators of any es requirements for owners one another.

CCR surface impoundments or operators to conduct a exceeding a size threshold number of structural integri(i.e., a height of 5´ or more and a storage volume of 20 acre-feet ty-related assessments on a regular basis. These include periodic or more; or a height of 20´ or more) also must conduct annual hazard potential classification assessments, periodic structural inspections of the CCR unit throughout its operating life. These stability assessments by a qualified professional engineer, and annual inspections focus primarily on the structural stability periodic safety factor assessments (factors of safety for slope staof the CCR surface impoundment and must ensure that the bility). Owners or operators of units required to conduct safety operation and maintenance of the unit is in accordance with factor assessments that fail to demonstrate that the unit achieves recognized and generally accepted good engineering practices. the specified factors of safety must close the unit. Additionally, Annual inspections must be conducted and certified by a qualiCCR surface impoundments with a high or significant hazard fied professional engineer. potential classification are required to develop an emergency

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June 2015

REGULATIONS COMPLIANCE Finally, the rule requires inspections by a qualified person of all existing and new CCR landfills and any lateral expansion for any appearances of actual or potential structural weakness, or any other conditions that are disrupting or have the potential to disrupt the operation or safety of the CCR landfill. Annual inspections also are required by a qualified professional engineer at intervals to ensure that the design, construction, operation and maintenance of the CCR landfill is consistent with recognized and generally accepted good engineering standards.

Closure requirements Closure and post-closure care criteria established in the new rule require all CCR units to close in accordance with specified standards and to monitor and maintain the units for a period of time after closure, including the groundwater monitoring and corrective action programs. Closure of a CCR unit must be completed either by leaving the CCR in place and installing a final cover system or through removal of the CCR and decontamination of the CCR unit. The final rule establishes timeframes to initiate and complete closure activities.

Recordkeeping, notification and internet posting requirements Although the requirements of the final rule are self-implementing, citizens and states can enforce the regulations through citizens’ lawsuits under section 7002 of RCRA. EPA also has authority under RCRA (section 7003) and the Comprehensive Environmental Response, Compensation and Liability Act (Superfund or CERLA) to compel compliance with the regulations and, if necessary, closure and cleanups.

To ensure that states and citizens have the information they need to initiate citizens’ suits for non-compliance, owners or operators of CCR disposal units are required to document that they have complied with the requirements of the rule. This documentation must be certified by a qualified professional engineer, kept in the operating record, and placed on a publicly accessible internet site. In addition, owners and operators are required to provide notification to states and/or appropriate tribal authorities when the owner or operator places information in the operating record.

Conclusion EPA’s CCR rule addresses the risks from CCR disposal; specifically, leaking of contaminants into groundwater, blowing of contaminants into the air as dust, and the catastrophic failure of CCR surface impoundments. Additionally, the rule sets out recordkeeping and reporting requirements, as well as the requirement for each facility to establish and post specific information to a publicly accessible website. This final rule also supports the responsible recycling of CCRs by distinguishing safe, beneficial use of CCR from disposal. Additional details on the rule can be found at http://www2.epa.gov/coalash/coal-ash-rule. ~

References 1. American Coal Ash Association’s Coal Combustion Product Production & Use Survey Report http://www.acaa-usa.org/ Portals/9/Files/PDFs/revisedFINAL2012CCPSurveyReport.pdf.

2. U.S. EPA:What is coal ash? http://www2.epa.gov/coalash/coal-ash-basics.

3. U.S. EPA: Human and Ecological Risk Assessment of Coal Combustion Residuals, Final, December 2014.

(Available at www.regulations.gov, Docket ID No. EPA-HQRCRA-2009-0640.)

4. U.S. EPA: Damage Case Compendium,Volumes I – III, December 2014. (Available at www.regulations.gov, Docket ID No. EPA-HQ-RCRA-2009-0640.)

5. U.S. EPA Region 4:TVA Kingston Fossil Plant Fly Ash Release http://www.epa.gov/region4/kingston/index.html 6. U.S. EPA:TVA Kingston Fossil Fuel Plant Release Site http://www.epakingstontva.com/default.aspx 7. U.S. EPA North Carolina outpost On-Scene Coordinator http://www.epaosc.org/site/site_profile.aspx?site_id=9065 Mathy Stanislaus was nominated by President Barack Obama for the position of assistant administrator in EPA’s Office of Solid Waste and Emergency Response (OSWER) on March 31, 2009, and began in his position June 8, 2009, after confirmation by the U.S. Senate. He is responsible for the EPA’s programs on hazardous and solid waste management under the Resource Conservation and Recovery Act (RCRA), contaminated site cleanup under RCRA corrective action, Superfund and SELL • RENT• LEASE federal facilities cleanup - 24 / 7 and redevelopment, EMERGENCY SERVICE Brownfields, oil spill prevention and response, chemical accident prevention and preparedness, underground storage IMMEDIATE DELIVERY tanks, and emergency response. Stanislaus is a chemical engineer 10HP TO 250,000#/hr and environmental 250,000#/hr Nebraska 750 psig 750 TTF 150,000#/hr Nebraska 1025 psig 900 TTF lawyer with more than 150,000#/hr Nebraska 750 psig 750 TTF 20 years of experience 150,000#/hr Nebraska 350 psig 115,000#/hr Nebraska 350 psig in the environmental 80,000#/hr Nebraska 750 psig 75,000#/hr Nebraska 350 psig field in the private and 60,000#/hr Nebraska 350 psig 40,000#/hr Nebraska 350 psig public sectors. You 20,000#/hr Erie City 200 psig may contact him by 10-1000HP Firetube 15-600 psig ALL PRESSURE AND TEMPERATURE COMBINATIONS emailing editorial@ SUPERHEATED AND SATURATED woodwardbizmedia.

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MR. MEGAWATT

Blowing bellows

By Frank Todd, True North Consulting

Have you ever noticed that power plants sometimes seem to have a devious inclination? I think if we did a histogram of the significant issues requiring immediate engineering attention, the bell curve would settle right at Friday afternoon between the hours of 3 p.m. and 6 p.m. When this happens, human nature wants to jump to the quickest solution possible so as to not spoil that weekend trip or that special dinner.

Waking up in yet another of my standard home away from home hotels where the only difference is the consistency of the oatmeal being served from 6 a.m. to 10 a.m., I was at least pleased that it was the end of the week, so I was on my way back to the Bluff to see Mrs. Megawatt and my faithful thermal performance golden retriever (in that order, of course). Even before I choked down the barely brown coffee, my cell phone was requiring attention from a far off land with what they thought was a serious condenser problem.

Figure 1

Figure 2

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The ZWBB power station somewhere in Asia (the actual location was censored) wanted confirmation of the analysis of a problem they were having at the plant. It was the day before the beginning of the Spring Celebration and everyone wanted this resolved before the next day. The engineers believed that they had a problem with their condenser and just wanted us to verify that they were correct. The culprit was assumed to be the degraded efficiency of the condenser, based on Figure 1. They were concerned that the drop in generation for the change in condenser pressure was too high.

These are the kind of jobs that we dream of, they have already done all the work and all we have to do is review their effort, put on a tie, verify that we are more than 50 miles away and send our conclusions that their engineers did it all right.

Especially since this was way more than 50 miles away (more like 5,000 miles), we were even happier when they told us that it had been reviewed,V&V’ed and approved by the top people.

Of course, with all this we sort of wondered why they were coming to us. That little engineer in my head told me not to be so glib about it.

As usual, we asked them to send all the pertinent information and that was our first inkling that something was amiss.

In their mind, the pertinent information was the graph they sent (Figure 1). We then made our fatal mistake; asking for a lot more data and the design information for their plant, particularly the condenser. Being part of a society that is reluctant to spread its information around, they said that if we needed more we would have to come and get it. I think it might have also had to do with the fact that we could not get there until after their Spring Celebration (a.k.a. New Year’s).

I figured we were in quite a pickle until I remembered our ace foreign travel expert, Ronny China. Not only was Ronny the most adept cross cultural conqueror he is also the prestigious Chairman of the International Committee for the Universal Measurement of Pumps (ICUMP), and he looks great in a tie. My confidence level greatly increased.

RC and I jumped on a few planes and after a mere 28 hours arrived at the ZWBB international airport ready to tackle any problem. That is after a 16(ish) hour train ride where we both learned that the idea of personal space was nonexistent in the country we had entered. Finally we made it to the ZWBB official hotel and, after wandering around for a couple of hours looking for our room, someone told us that the first number of our room number was a “lucky” number and did not mean anything.

After a hearty breakfast, RC and I bounced along the roadway arriving at the plant to finally engage the problem. We attended an official meeting with all the plant management and half of the engineering organization and were taken to a secure area through a series of “get smart” doors where we could look June 2015

MR. MEGAWATT

Figure 3

at some data. The first thing on the list was the thermal kit of the plant so we could try to figure out the various correction curves (Based on ASME PTC-6) that would allow us to identify known losses and develop a curve of generation corrected for the effects of condenser pressure. Based on their initial analysis we looked at the condenser to see if that was the issue. This involves an evaluation of the circulating water inlet temperature, flow and condenser pressure. Circulating water flow is shown in Figure 2, which shows that it did not change during the time period. We obtained the design information for the condenser and developed an equation for the expected condenser pressure for the circulating water inlet temperature. With this information, a comparison between the actual condenser pressure and the expected condenser pressure could be developed (see Figure 3). Since the expected condenser pressure was tracking with the actual condenser pressure, the problem was not in the condenser.

During dinner, RC was able to convince the ZWBB engineers that the problem was not in the condenser. I was a little oblivious and somewhat afraid of the cuisine but RC, using his skills with the Ganbei process, had them all eating out of his chopsticks (literally). Even though RC was able to smooth over the condenser issue, they still wanted to know what the problem was.

The next morning, after recovering from the previous evening’s digestive anomalies and the perilous drive to the plant, we put together a graph of corrected generation with condenser pressure, Figure 4. What we noticed was that the corrected generation actually decreased before the condenser pressure increased. This means that something happened before the change in circulating water temperature. Now we had to start at the beginning of the cycle and try and figure out the real issue. Figure 5 is a drawing of the type of plant we were dealing with and we essentially started walking through the cycle to identify what the possible issue could be.

Starting at First Stage Pressure and the first point extraction pressure Figure 6, we looked at trends of all the turbine extraction pressure to see if we could find any issues. When we got to the extraction pressure for the 3rd and 4th stage on the south Low Pressure turbine, it was clear that those pressures had

Figure 4

Figure 5

Figure 6

decreased with respect to the other LP Turbines, see Figures 7, 8 and 9. Figure 10 shows that the change in corrected generation corresponded with the change in the extraction pressure to the 4th stage of the LP turbine. So we knew that there was a problem somewhere between the LP turbine and the feedwater heater since there was no abnormal indication of the feedwater heater TTD’s. Based on the sudden change of the pressure, we suggested that there might be an issue with one of the expansion bellows between the LP turbine and the feedwater heater.

The expansion bellows are installed on the piping between

June 2015 ENERGY-TECH.com

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MR. MEGAWATT

Figure 7

Figure 8

Figure 9

Figure 10

the turbine extraction nozzles and the feedwater heater. The bellows allow for differential movement between the feedwater heater and the turbine extraction line.

Once again, Ronny was on the scene to explain all this to our engineering counterparts in such a manner that they were very happy and scheduled an inspection for their next outage.

Ronny even volunteered to go out and help them with their inspection during the outage. Figure 11 is a picture of a bellows rupture that is very close to what they found during the inspection.

Ronny and I were both very happy to get back where the population density is at a level where the macroscopic cross-section for bumping into someone was greatly diminished, and I know he is looking forward to his next trip. ~ 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. You may email him at editorial@woodwardbizmedia.com.

Figure 11

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June 2015

ASME FEATURE

Wind system reliability and capacity

By Alex Pavlak and Harry V. Winsor, Future of Energy Initiative

Two types of capacity problems are relevant to electrical on 100- or 500-year floods. Airports are designed to manpower systems (Billinton 1984): age a maximum of so many passengers and planes.

“The total problem can be divided into two conceptualThe extreme event is a primary design criterion that is ly different areas designated as static and operating capacity usually defined using historical statistics. The engineering requirements. The static capacity relates to the long-term task is to design the system to survive the event at a given evaluation of the overall system requirement. The operating level of reliability. For electrical power systems, the Federal capacity area relates to the short-term evaluation [of] actual Energy Regulatory Commission requires a reliability critecapacity required to meet a given load level.” rion of one-day-in-10-years, or 0.00027. One-day-in-10This paper focuses on classical system capacity, what years is a heuristic reliability threshold. It does not imply Billinton called static capacity. An early (pre-1970) critea blackout for one day every 10 years. This criterion is far rion was deterministic: the expected maximum demand out on the tail of any distribution where classic statistical plus a fixed percentage of the expected maximum demand. calculations are unreliable. Based on decades of experience, More recently, an IEEE Task Force legacy system managers found that defined capacity value for elecat this reliability level, they can Adding wind generation to a trical systems as “the amount of avoid black/brown outs through additional load that can be served emergency imports and/or demand legacy fossil fuel system has due to the addition of the generamanagement. little impact on classical system tor, while maintaining the existing Lastly, system capacity should capacity unless stand-alone wind levels of reliability.” This is correct not be confused with average provided it is understood that there capacity. The former is a measure has reliable system capacity. is considerable variation in wind of generation equipment requirepower availability. ments to satisfy estimated peak The capacity of any system is measured by its ability to load, the latter is the average system power produced during function reliably during extreme events. It is the outliers, a period of time. the maximum stresses, that determine the size and strength (the capacity) of the system. For example, in the structural Origins of system reliability & capacity engineering world, hurricanes and floods often become the The green dotted line in Figure 1 shows the cumulative basis for system design. The BOCA building code requires exceedance distribution function (EDF) for a system conthat the design wind speed be the fastest mile per hour sisting of two generators. The EDF is the probability that measured at 33´ above the ground with an annual probthe system power exceeds the power level on the horizontal ability of 0.02 (50-year wind). More generally, structures axis. The size of each generator is 50 power units and each are designed to reliably withstand the highest wind load has a 3 percent forced outage rate (availability = 0.97). expected during the life of the structure, with a reasonable The probability that the system power exceeds 100 is zero. safety factor. Likewise, flood control systems are often based This two-generator system can have a power level between 50 and 100 only if both generators are operating and that

Nomenclature

ACF – Average Capacity Factor – The percentage of a wind generator’s nameplate capacity actually produced under average wind conditions.

BOCA – Building Officials Code Administrators CDF – Cumulative Distribution Function: The probability that a power system’s output is less than a given power level.

EDF – Exceedance Distribution Function: The probability that a system can supply power exceeding a given load.

June 2015 | ASME Power Division Special Section

EirGrid – The Irish electric power system ELCC – Effective Load Carrying Capacity: A statistical technique for measuring system capacity.

LOLE – Loss of Load Expectation: A reliability criterion, typically one-day-in-ten-years or 0.00027, or 2.5 hours per year MISO – Midcontinent Independent System Operator PJM – PJM Interconnection, LLC: The largest independent system operator.

ENERGY-TECH.com

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ASME FEATURE probability is: P{50<system powerâ&#x2030;¤100} = 0.972 = 0.9409.

The system can have a power level between 0 and 50 if either one or both generators are working: P{0 <system powerâ&#x2030;¤50} = 0.9409 + 2*0.97*0.03 = 0.9991.

The remaining curves in Figure 1 show how increasing the number of independent generators builds up a shoulder on the EDF curve. It is that shoulder that provides an effective system, with high system availability at high power levels. None of the curves reach unity (100 percent availability) because no one generator is perfect, but they come close.

For the five-generator system, Figure 2 logarithmically expands the scale in the vicinity of unity to show that as the power required from the system is reduced, the reliability curve asymptotically approaches unity. There is a finite probability that all five of the independent generators will fail simultaneously. With a generator forced outage rate of 3 percent, the likelihood of this occurrence is 0.035 or 2.4 x 10-8.

Parallel connection of generators with independent forced outage rates is an extraordinarily powerful way to build reliable systems that have availability much greater than that of individual generators. With 100 equal-sized generators (roughly the scale of the PJM Interconnection) each with 0.97 availability during peak demand, the probability of losing all power because all generators failed simultaneously is 10-153. The probability of finding one specified atom in the universe is only about 10-80.

Effective load carrying capacity (ELCC) ELCC is a statistical technique that was developed during 1950-1980 to calculate a reliable power level for an electric power system. ELCC is essentially synonymous with classical system capacity.

The red curve in Figure 1 shows the EDF for a system of 100 generators each with a nameplate rating of 1.0 and an independent random forced outage rate of 3 percent.

The system nameplate is 100 and since each generator has an availability of 0.97, the maximum average capacity of the system is 97.

At what power level does the system have adequate reliability? That power level is called the Effective Load Carrying Capacity. The system ELCC is established by a reliability criterion, a Loss of Load Expectation (LOLE).

Using the most common industry criterion, a LOLE of one-day-in-10-years or 0.00027, Figure 3 says that this system could operate reliably at power levels <90.2: That is the ELCC. Stand-alone wind systems An important question is whether a stand-alone wind system has any ELCC corresponding to an LOLE = 0.00027. If it does, then wind would clearly contribute to the capacity of a mixed generator system. Figure 4 shows

22 ENERGY-TECH.com

ASME Power Division Special Section | June 2015

ASME FEATURE the EDF calculated for several stand-alone wind systems.

The solid red curve is the same as that in Figures 1 and 3.

The dotted black curve is the EDF for a single (Vestas 3 MW) wind farm with Rayleigh wind fluctuations and an average capacity of 0.25. The purple dash-dot curve is the EDF for stand-alone wind on the PJM grid for 2012. The long-dash green curve is the EDF for stand-alone wind on EirGrid for 2012. The black boxes are EDF data reported

by Cox for the British market in 2007.

The EDFs for PJM, EirGrid and the British market are remarkably similar and dramatically different than the EDF for the high reliability reference scenario and the Vestas farm. This shows that wind generators must be analyzed differently than classical generators.

The question of whether stand-alone wind has any ELCC is determined by what happens in the upper lefthand corner of the EDF chart. LOLE is a reliability criteria used to calculate ELCC. So the first step is to look at the annual time series to see if the system loses power for more than 2.5 hours per year. In that event, wind has no system capacity as defined by the usual LOLE. Table 1 shows the number of hours that different standalone wind systems have negligible production. From a practical perspective, wind farms consume a small amount of electric power as part of normal operations, so there is a finite threshold below which no net power is produced.

Some operators report wind as net power, others do not.

Figure 1. System EDFs for several generator sets.

ASME Power Division: Reliability, Availability & Maintainability Committee

A Message from the Chair Ask yourself this question, “If some thing or process could be standardized by ASME that would directly improve the reliability, availability or maintainability of your power plant, what would it be?”

For decades, data was compiled to try to answer this question, and finally there was enough for the justification to form the ASME Reliability, Availability and Maintainability (RAM) Committee. There was a clear demand from the industry that RAM of power plants was needed. Something to standardize how a plant could establish stable and controllable reliability, availability and maintainability – with measured results.

The first RAM Standard (ASME RAM-1-2013) was issued two years ago and since then the momentum has not stopped. The RAM Committee is about to publish its next standard, ASME RAM-2-2015, which, in response to industry demand, is focused on exactly how to implement (with actionable tasks) a RAM Program into an existing power plant. I am proud to be a part of this high-energy group of motivated committee members.

Standards committees are simply volunteers within the industry, who are willing to put forth some time and effort to create a needed standard. However, even though committee membership is intentionally diversified, they typically only represent a small portion of the industry.

Do not forget that you are the power plant “industry.”

Write, speak and be heard.Your voice is just as important – if not more – than of those on any committee.

Your experience, expertise and knowledge are invaluable to committee work. Do NOT underestimate your value.

Any question you might have, any advice you might offer, or any bit of information is appreciated. Please reach out to anyone at ASME and ask how you could support the development of a standard you choose or, if so motivated, even be involved in a committee.

You do not need a special reason to contribute to the development of a standard; but it just might be the perfect opportunity to give back and be recognized for your hard work and the sacrifices you put into this industry.

Thanks, Brian Wodka brian.wodka@rmf.com

Figure 2. Log EDF for five generators.

June 2015 | ASME Power Division Special Section

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ASME FEATURE

Figure 3. Calculating system ELCC

Figure 5. ELCC calculations PJM2013

For this reason, Table 1 presents the number of hours that system production is less than 1 percent of nameplate.

In LOLE, a wind system can be considered to have some capacity if its production is negligible for less than 2.6 hours per year. The 100-unit reference scenario dramatically exceeds this criterion. In contrast, all of the wind scenarios fail this criterion. There is no evidence that stand-alone wind has any system capacity as classically defined by oneday-in-10-years.

Some have argued that long distance transmission connecting widely dispersed wind farms will provide system capacity. Kempton claims that a synthetic data set for a wind system extending from Maine to the Florida Keys never dropped to zero during a 5-year period. This claim appears exaggerated in that Figure 4 of that report shows whiskers dropping so close to zero that it does not make a meaningful difference; and Kempton does not calculate net wind. No physical law says net wind will never drop to zero. Therefore, stand-alone wind has no ELCC.

24 ENERGY-TECH.com

Figure 4. EDFs for stand-alone wind

“Preferred methodology” An IEEE Task Force adapted classical ELCC to wind systems by viewing wind as negative load. The Task Force calls this methodology “preferred” because it correctly preserves any wind-load correlation. By subtracting each hour’s average wind from the average load for the corresponding hour, we create a third time series: “load minus wind.” This load minus wind time series is the power that must be reliably serviced by dispatchable backup generators. The CDFs for PJM 2013 load and load minus 10 percent wind time series is then calculated and presented as the blue dashed line in Figure 5. It is normally plotted by ordering the hourly results from lowest to highest, as shown in Figure 5.

The CDF curves are spread farther apart at lower load and come together at higher load. At low system power, 10 percent wind reduces the traditional generation requirements by more than 10 percent. At high system power, 10 percent wind has less impact. Figure 5 illustrates the negative correlation between wind and load by plotting both load and load minus wind, which accurately indicates the varied spacing observed, as well as the slow growth of the separation as the load decreases. Here, the lowest wind does not occur at the highest load, so the critical reliability condition might not be at the highest load. Note that at the highest load, the load minus wind curve is separated by only 1.4 GW, which is less than 1 percent of load. Yes, with a wind penetration of 10 percent of average load, the need for dispatchable generators at peak load was reduced by only 1 percent in 2013!

One year of data is clearly insufficient. Some systems make a further serious mistake by averaging the annual ELCC calculations across multiple years. The correct approach for system capacity is to calculate the capacity for each year separately and then look for the worst event during the life of the system (decades). While we do not yet have decades of real wind generation data, it should be obvious that if the stand-alone wind goes to zero, it is like-

ASME Power Division Special Section | June 2015

ASME FEATURE ly that stand-alone wind will eventually go to zero during peak load and the wind ELCC will approach zero.

The flaw of averages The purpose of calculating system capacity is to determine how much long-term dispatchable generation capacity is necessary to achieve reliable operations at any time of day or year. With this purpose, averaging annual ELCC is not logical. Strong year-to-year variation is caused by how low and high wind events correlate with peak load for that year. Since the system must have sufficient capacity to operate reliably during peak-load low-wind events in all years, the correct method is to use the minimum ELCC, not the average. Based on Table 1, the wind system capacity on the MISO grid is ≤2.8 percent and trending toward zero (not 14.7 percent). From one data point (2013 at 10 percent penetration), the corresponding number for PJM is ≤6 percent (not 13 percent).

If MISO reduced natural gas backup capacity by 14.7 percent and then another 2.8 percent ELCC year came along, the MISO grid would have a capacity shortfall of 11.9 percent of wind name90° Prism & plate during that event. As wind penetraClose-Focus tion into the grid increases, the absolute tips available! shortfall increases accordingly.

load. Empirical data show that wind on a power grid might eventually drop to zero. There is no physical reason why any stand-alone wind system’s production cannot drop to zero. Given enough time there is no reason why zero wind cannot correspond to peak load. Therefore, wind must be analyzed as a single large generator: Cumulative wind production for the whole system.

To calculate system reserve requirements using a complex set of models obscures the issues. For this analysis, the simple assumption is that dispatchable generator forced outages are statistically independent and can be represented

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Conclusions and recommendations Classical system capacity quantifies a system’s ability to reliably function during extreme stress. The main purpose for calculating system capacity is to determine system reserves, the generation assets necessary to maintain desired levels of reliability.

An IEEE Task Force defines wind system capacity as “the amount of additional load that can be served due to the addition of the generator, while maintaining the existing levels of reliability.”

The Effective Load Carrying Capacity (ELCC) method used in this paper accomplishes this.

Adding wind generation to a legacy fossil fuel system has little impact on classical system capacity unless stand-alone wind has reliable system capacity. Standalone wind system performance does not resemble that of legacy power systems.

Figure 5 presented evidence of a negative correlation between wind production and

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ASME FEATURE Table 1 – Number Of Hours That System Production Is <1 Percent Of Nameplate System

Hours

LOLE requirement (one-day-in-10)

<2.5

Reference – 100 independent fueled

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PJM 2012 wind

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EirGrid 2012 wind

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26 ENERGY-TECH.com

by Gaussian probability density functions. The Exceedance Distribution Function for Gaussian statistics is illustrated by the red curve for 100 units in Figures 1, 3 and 4.

Figure 4 shows that wind generation statistics are different and are not represented by a simple analytic model.

The empirical data presented in this paper shows that wind generators contributed <6 percent of wind nameplate to system capacity for PJM in 2013. Additional data is likely to drive this number down further. Incorporating detailed wind statistics into the PJM Generation Adequacy analysis would require a major overhaul of the whole system of models, and would only make small changes in the number of dispatchable generators needed.

A simple, conservative approach is to calculate Installed Reserve Margin in the usual manner using conventional generators without wind. If additional analysis shows that wind does contribute x percent to system capacity, this could be applied as a small correction to the conventional result.

The practice of averaging annual worst case events rather than identifying the extreme worst case event is widespread. This results in overestimating the contribution of wind to system capacity. This type of error can occur when working near the tail of any distribution. Based on data from PJM and MISO, wind augmented systems need the same reserves to maintain reliability as they would need if there were no wind generators on the system. Therefore, wind is only an energy source, not a capacity resource.

Literature claims of wind contributing 5-40 percent to system capacity are therefore flawed, in part the result of confusing classical system capacity with average capacity. ~ Editor’s note: This paper, PWR2014-32148, was printed with permission from ASME and was edited from its original format. To purchase this paper in its original format or find more information, visit the ASME Digital Store at www.asme.org.

Alex Pavlak, received his Ph.D. in mechanical engineering from Stevens Institute of Technology and holds a PE license. He has 45 years’ experience developing various first-of-a-kind systems. You may contact him by emailing editorial@woodwardbizmedia.com.

Harry V. Winsor, received his Ph.D. in Engineering/Applied Science from University Of California, Davis. He has 50 years’ experience in designing and managing the development of state of the art systems.

You may contact him by emailing editorial@woodwardbizmedia.com.

Dedicated to the Engineering, Operations & Maintenance of Electric Power Plants

ASME Power Division Special Section | June 2015

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TURBINE TECH

Crossing the retirement finish line with high temperature steam turbine rotors

By Stephen R. Reid, PE, and Rachel Sweigart, TG Advisers Inc.

Background New environmental regulations and the installation of renewable energy sources have resulted in many retirements of older legacy steam turbine generating units. Most of these older units have spent the majority of their life in operation “base loaded.” As a result, they have logged significant operating hours with few on/ off cycles. Long-term, temperature dependent damage mechanisms of these turbine rotors must be considered to ensure successful operation to the desired retirement dates. This article highlights two case studies and some operational strategies to extend life to the desired retirement date.

Consider high temperature, life limiting mechanisms HP and IP rotors with material properties similar to ASTM A470 typically operate with steam inlet temperatures of 1,000°F. With time, creep cracks can initi- Figure 1. Larson Miller Parameter Curve ate in highly stressed areas. In addition, the material can ation (see Figure 1). The LMP approach does not account for suffer significant embrittlement with time, reducing the crack propagation and/or the interaction of creep and fatigue material ductility that is an important property for remaining from on and off cycling. The industry has utilized a fracture life analysis. These mechanisms are at play in the rotor bore and mechanics approach to assess life once cracks have initiated, blade attachment sections. and/or to assess pre-existing cracks in high temperature zones of steam temperature rotors.

Creep As noted in Figure 1, there can be a significant scatter of Creep is a time, temperature and stress dependent mechcreep material data. The OEMs will add additional safety maranism that must be considered for units with a significant gins and define a “Design Curve,” which is always lower than number of service hours. For creep cracking, rotor the curve produced from the minimum test points. As a result, operating temperatures in general must be above units usually far exceed their 30-year creep design target. Rotor 800°F and a significant stress level must be preslife is often limited by pre-existing flaws that are developed ent at all times to be concerning. Creep life from the forging process.

This is especially true of rotors protargets of 30 years are frequently quoted duced prior to forgings, which were manufactured using vacuby OEMs for high temperature rotor um degasing technology (i.e. air melt process). designs. Design life is typically

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Embrittlement Dr. Swami Swaminathan of TurboMet International, while under contract by Electric Power Research Institute (EPRI project 2481-5) performed testing on a retired rotor to support needed materials data for life assessments of service exposed rotors. Testing provided many concerning changes in material properties with time and temperature. A main area of concern was the large degree of rotor embrittlement during the relatively short operating period of less than 200K hours. The degree of embrittlement was quantified by a shift Fracture Appearance Transition Temperature (FATT). The FATT defines the tem-

June 2015

TURBINE TECH perature at which the rotor steel exhibits 50 percent brittle and ductile behavior. The resulting critical crack sizes that define the burst condition for a rotor are directly related to the material’s ductility. This parameter is important since it helps to define the required rotor soak period to ensure the material is ductile when it is exposed to high stresses during cold starts.

Swaminathan completed testing in different steady state operating temperature zones at the bore and peripheral locations. The work proved longterm exposure to temperature could increase the FATT by approximately 200°F. Another Figure 2. Critical crack size comparisons for prior and optimized startup curves interesting fact was that embrittlement did not occur in the lower speeds without detrimentally affecting differential expanhighest operating temperature zone. Embrittlement was more sion. The plot below shows a potential improvement of 400 pronounced in the zone where temperature was in the 800°F percent in critical crack size for a modified cold start. Adapting range. the revised startup procedures has allowed this utility to stay on As a result of these efforts, pre-existing flaws in rotors have track with its retirement plan. Follow up analysis of the actual required a more conservative material property boundary conrevised startup practice has shown a close match to the recomdition to assess risks of brittle fracture. In many cases, embritmended curves. tlement has limited the number of stops and starts and/or has resulted in premature retirement of aging rotors.

Control stage failure

Notable case studies IP rotor embrittlement As a result of a recent failure of an IP stage 2 dovetail, TG Advisers had an opportunity to evaluate the embrittlement condition on a rotor that logged more than 425K of operating hours. The resulting shift in FATT was significantly greater than expected. The FATT for the stage of concern had increased to more than 600°F which was approximately 300°F higher than a non-embrittled rotor steel of the same chemistry.

With retirement planned in the near future, the utility decided to remove the stage and evaluate methods to ensure reliable operation until the unit’s retirement date. During the remaining operating window, the unit was expected to have just a few cold starts, which are the most concerning for an embrittled rotor. A decision was made by the evaluating team to assess modifications of the existing rotor cold start procedure to account for the FATT shift. Multiple startup simulations were run varying speed, hold times and ramp rates to ensure high stresses occurred only after the rotor achieved a ductile state. The evaluation also included an assessment of differential expansion, which was significantly changed with longer soak periods.

The results of the analysis proved the embrittled rotors could achieve ductile properties by extending soak periods at

Another notable failure was experienced on an inlet stage of an HP turbine that had accumulated more than 300K hours of operation (see Figure 2).

The failure provided an opportunity for the utility to test larger sections of the control stage disc to determine if a weld repair was feasible. The test program included: • Rotor Boresonic Tests (MT, UT, visual) • Material Tests (actual rotor material) ›› Tensile Tests (detect creep softening) ›› Impact Tests (estimate fracture toughness) ›› Accelerated Creep Rupture Test Testing proved the failure to be attributed to high temperature creep notch sensitivity in

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the stress concentrated area of the rotor dovetails. Following an assessment of the rotor material properties at various radial locations, a cut line was established and the rotor was built up, stress relieved, re-machined and new blades installed. The repair was successful and the unit achieved its desired retirement date of approximately 10 years after the repair. ~

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Acknowledgements TG Advisers would like to thank the Consumers Energy team of Matthew T. Helms, Vladimir Trbulin and Mark E. Wittbrodt for their technical support and direction with the HP and IP rotor assessments. TGA also would like to thank Dave Sheasley, Roger Karn and Mark Miller of NRG for the technical support with the HP rotor control stage assessment efforts.

Stephen R. Reid, P.E., is president of TG Advisers Inc. and has more than 30 years of turbine and rotating machinery experience. Reid and his team provide turbine troubleshooting, health assessments and expert witness services to major energy companies in the U.S. and have provided condition assessment evaluations on more than 100 turbine generators in the U.S. Reid also is a short course instructor for EPRI, ASME, Electric Power and POWERGEN, has numerous patent disclosures and awards, and published more than 20 technical papers and articles. Reid was the recipient of the 1993 ASME George Westinghouse Silver Medal Award for his contributions to the power industry and is past chairman of the ASME Power Generation Operations Committee. He is a registered professional engineer in the state of Delaware. You may contact him by emailing editorial@woodwardbizmedia.com.

Rachel Sweigart joined TG Advisers in 2014 as a consulting engineer. She has provided life assessment, analytical modeling and troubleshooting services for main turbine generators located throughout the country. Sweigart is a mechanical engineering graduate from Lafayette College. You may contact her by emailing editorial@woodwardbizmedia.com.

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