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the Conduit A quarterly publication from M&M Engineering Associates, Inc.

Vol. 10, No. 2

By Max Moskal Part 1 and Part II of Inspection and Repair of Batch Digesters, published in the previous issues of the Conduit, described the types of stainless steel weld overlays for corrosion protection and corrosion “hot spots” in the digester. Part 3 – Nondestructive Testing and Keeping Records

Nondestructive Testing It is typical to perform and document annual inspections of the interior and the exterior (to the extent it is not covered by insulation) of batch digesters. The reader should consult TAPPI TIP 0402-22 “Guidelines for Batch Digester Inspections,” for details on digester inspections. Relevant jurisdictional inspection interval requirements may also define the inspection frequency. Visual inspection is most important (Fiigure 1). Visual examination will determine all other testing and inspections necessary, such as liquid penetrant (PT), magnetic particle (MT), and ultrasonic thickness (UT). If not already performed, a “baseline”

inspection should be done involving more extensive inspection, testing and analysis than a regularly scheduled inspection. The following discussion provides additional background to the above-mentioned TAPPI TIP 0402-22 Guideline. Ultrasonic thickness testing (UT) is almost always made on an annual basis for carbon steel digesters that have not yet been weld overlaid. The above-mentioned TAPPI TIP Guideline also describes types of UT surveys. The UT survey is critically important prior to the first stainless steel overlay since it provides a baseline for the required minimum thickness. Very old digesters may have been overlaid without the carbon steel thickness documented and require special attention. The digester may be UT tested for the total thickness of the carbon steel base metal plus the overlay. A problem is immediately apparent if the total thickness does not meet the required thickness for the combined carbon steel plus the suspected thickness of the stainless steel overlay (normally 4.8-mm when first applied). In such cases, more comprehensive UT inspection can be performed where the bond line of carbon to stainless steel can be observed. The approximate bond line of stainless to carbon steel can be observed by scanning the surface with a special UT equipment setup and appropriate transducers. The equipment and skill of the personnel are specialized and first should be evaluated using overlaid test weld specimens. Another option is to determine the overlay thickness by localized grinding through the overlay weld, which then requires repair of the overlay.

Weld defects must be found and repaired before significant corrosion damage occurs. Localized corrosion of the carbon steel beneath the overlay can be much more rapid than large areas of exposed carbon steel (Figure 2.).

Because of the large areas to be tested, water-washable penetrants are preferred over solvent-removable penetrants. The surface roughness inherent in as-welded or corroded overlays often creates problems of excessive false indications with all PT methods. Liquid penetrants are available with up to five degrees of sensitivity (Level ½ to 4, with Level 4 being the most sensitive) and it is important to compromise between the testing sensitivity and the surface roughness. As-welded surfaces may be tested using Zyglo® ZL-60D, or equivalent, a Level 2 water-washable fluorescent Type 1 penetrant. Best results can be obtained in PT inspections by

(Continued on page 2)

Employee News .................................... 6 Chemically Cleaning the Boiler ......... 3 Combustion Turbines-The Basics ..... 4

In this Issue Inspection and Repair of Batch Digesters Part 3 of 3

Figure 1. Regular visual inspection is necessary for detection of problems and to make timely repairs. Shown here is a start-stop defect in GMAW automatic overlay weld – Type 312 stainless steel.

Figure 2. Pin-hole defect with car-bon steel bleed-back in GMAW automatic weld. Weld repair must be performed as soon as the flaw is detected to avoid extensive corro-sion of the carbon steel base metal.

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ensuring that the surface is completely free of deposits, including pulp fiber. Questionable areas should be visually examined after light grinding and then retested with solvent-removable contrast dye penetrant. The PT method used may also be validated on samples of overlaid plate with known defects.

Keeping Records The matter of digester records is worth mentioning only because most mill departments give such low priority to this mundane task. Furthermore, recordkeeping is sometimes relegated to the new employee assuming responsibility for the task. In the process, old records may be lost because their importance is not recognized. Computer management of digester records should make this task easier. One purpose of pressure vessel record management is to assess needed repairs in advance so that the work can be planned in a timely and cost-efficient manner. Recordkeeping for batch digesters is critical once the ongoing weld overlay program has begun. For example, it is typical for a jurisdictional inspector to request proof that the carbon steel portions of the overlaid walls meet the required thickness. The answer may be impossible to obtain once overlay has been applied. Another common mistake in recordkeeping is to maintain only an approximate description of the amount and the locations of replacement overlay weld. When multiple patches of stainless steel overlay are present, it may be impossible to identify the type of weld metal used, age, or thickness of a specific application. Only by means of careful record management can one determine how many times the digester has been overlaid. Layout of the digester for recordkeeping purposes is usually best performed by the nondestructive testing contractor. Layout should be performed within +/- one inch. This close layout

tolerance ensures repeatable UT thickness tests year to year and helps to easily locate overlay repairs. Most mill maintenance and engineering departments already have data management protocols, but these should be occasionally reviewed for adequacy. At minimum, a list should be made of the necessary records to be maintained and to be consistent with the necessary data input. One cannot rely on the overlay applicator to make precise measurements of the amount and location of new or repaired overlay unless it is required in the work scope. Conclusions Corrosion of carbon steel and stainless steel overlays is site-specific in batch digesters. Regions of the digester contacted by the charging liquor (especially splashing liquor) are most vulnerable to corrosion. Many older digesters have been protected by stainless steel weld overlays, but the life span of the overlay is often shorter than expected in regions of the digester contacted by liquor. Today, batch digesters should be overlaid using Type 312 stainless steel weld metal applied by either the automatic SAW or GMAW weld processes. However, high quality applications are required and follow-up repair is important to ensure the best life of the overlay. As digesters age, second—and sometimes third—corrosion resistant overlays may be applied. Depending on several factors, the practical maximum thickness of overlay that can be applied without excessive distortion should be limited to about 10 mm (0.4-inches). Most batch digesters are inspected on the interior on an annual basis. Visual inspection is the most important inspection method to be supplemented by UT thickness and either PT or MT methods. Good recordkeeping of digester inspections and weld overlay application is essential.

By Dave Daniels

Chemical cleaning has been considered a necessary part of boiler maintenance for many years. The objective of a chemical cleaning is to safely remove all the deposits from the inside of the boiler tubes. In low-pressure boilers, chemical cleaning typically removes calcium carbonate and other hard adherent scales. In higher-pressure boilers, the major deposit removed is magnetite and some copper, nickel, chromium and phosphate. Chemical cleaning can improve the boiler heat rate and reduce the number of tube failures. It typically improves the stability of boiler chemistry as well. Not doing a chemical cleaning when needed, significantly increases the probability of boiler tube failures from a variety of corrosion mechanisms.

The chemical cleaning of a boiler is something that many a plant resists. Chemical cleaning horror stories abound. Usually problems arise when the chemical cleaning was rushed or when there has been insufficient planning or experience. When making the decision to chemically clean a boiler, it is important to remember that chemical cleaning is:

Expensive (vendor costs alone may be $50,000 to $100,000),

Potentially dangerous to personnel and equipment,

An environmental and chemical spill risk,

A waste handling problem, and

Time consuming—adding a week or more to the end of an outage.

Considering these risks and costs, the only thing worse than not chemically cleaning a boiler that needs it is chemically cleaning a boiler that doesn’t need it.

Chemically Cleaning the Boiler

A Matter of Timing

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When to Clean

In the past, utilities and other steam generators have considered a number of factors when determining the need to chemically clean. The most common criteria are: Deposit loading on tube samples, Operating hours since last chemical

cleaning, Calendar months since last

cleaning, and A major contamination incident

(condenser tube leak).

Following is a brief review of each of these criterion.

Deposit Loading One of the most common criterion is the deposit loading on the inside of the waterwall tube. Typically, the plant would take two or three boiler tube samples from the high heat areas of the boiler and have the deposit loading analyzed on each. An average of the hot-side loading on the tubes is compared against a chart similar to the one in Figure 1.

This is still the best way to determine the need to chemically clean, assuming that there have been no major contamination incidences since the last chemical cleaning. Time-Based Cleanings In the past, some boiler operators cleaned based on time—either the number of operating hours or the number of years since the last chemical cleaning. This is probably the worst way to determine the need to chemical clean

Deposits do not form on boiler tube walls at a uniform rate over time. Immediately after a chemical cleaning, the boiler tubes create a protective film of magnetite that limits further corrosion of the base metal. This quickly adds 5 or so grams/ft2 of deposits to the boiler. Over time, new deposits collect on top of this protective layer. These deposits typically come from the boiler feedwater. Boiler startup and

shutdown can add a tremendous amount of deposit to the boiler tube wall and is a better predictor of tube deposit density than operating hours alone.

Time-based cleanings do not consider water chemistry (good or bad) or the deposit loading on the tubes. It may be that the water chemistry control has been particularly poor and the deposit loading is high. In that case, the frequency should be increased. The opposite might also be true, and the chemical cleaning can be put off for years.

Contamination-Required Cleanings This criteria is often overlooked, particularly by those that clean on a set time schedule. If there is a major contamination of the boiler water, a chemical cleaning must be performed at the next opportunity, preferably before the unit is restarted. The most common contamination incidences are calcium hardness in the boiler from a condenser tube leak or demineralizer/softener malfunction. Corrosion cells are created during the contamination that lead to caustic gouging and hydrogen damage. In these cases, the large risk of major waterwall damage outweighs the risks associated with chemical cleaning.

An Ounce of Prevention Improvements in boiler and feedwater practices have reduced the need for chemical cleaning at many utilities across the country. These improvements focus on minimizing the amount of copper and iron corrosion-product transported into the boiler, more refined boiler chemistry, and better start-up and layup practices. With corrosion deposits minimized, the boiler tubing remains clean for many years. Added benefits to these improvements are better heat rate, fewer boiler tube leaks, and less loss in generation due to turbine deposits. Whereas, fifteen years ago, cleaning every two to three years was considered good practice, some boiler operators have extended the period between chemical cleanings to seven, ten or even twenty-year intervals by improving their layup and startup practices.

With the advent of oxygenated treatment (OT), first for supercritical units, and then for high pressure drum units, chemical cleanings could be stretched out nearly indefinitely. However, OT requires very stringent control of the water and steam chemistry.

Before You Clean Before making the decision to chemically clean, check the deposit

Deposit Loading

0

10

20

30

40

50

60

1500 1900 2300 2700 3100 3500

Drum Pressure

Cleaning Recommended

Consider Cleaning

No Cleaning Required

Cleaning Recommended

Consider Cleaning

No Cleaning Required

Figure 1. Determining the need to chemically clean by deposit density.

grams per sq. ft.

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density of at least two and preferably three boiler tube samples. If there haven’t been any major contamination incidences since the last chemical cleaning and if the deposit density isn’t in the “Cleaning Recommended” range, seriously consider not cleaning.

If there has been condenser tube leak or other contamination problem, schedule a cleaning at the next available opportunity. Look into changes to startup and layup procedures that may make chemically cleaning your boiler much less frequent.

Knowing when to clean and when not to clean can save you and your boiler considerable money and risk.

M&M Engineering can help you determine when or if you need to clean, the best solvent to use, and can manage the actual cleaning process.

Contact us before your next cleaning.

Combustion Turbines

The Basics

Figure 1. Overall view.

By Ronald E. Munson, P.E.

First of all, I send my apologies to those combustion turbine aficionados out there who are about to read this arti-cle—it will not enlighten you. This arti-cle will provide a short overview of combustion turbines for those not lucky enough to work with these en-gines everyday.

Combustion turbines, also referred to as gas turbines, range greatly in size from very small to quite large, with power outputs from a few kilowatts to 300 megawatts. Their fuel source gen-erally is natural gas, hence the term “Gas Turbine”, but can also be liquid fuels such as Jet Fuel A or waste gases. Some turbines even burn methane ex-tracted directly from municipal landfills.

Gas turbines generally have five func-tional components: 1. Inlet Air Handling System 2. Compressor 3. Combustor 4. Gas Generator (Hot Section) 5. Power Extraction System

Inlet Air Handling System The inlet air handling system is usually a massive structure that collects the am-bient air used by the combustion tur-bine (CT) and directs it into the com-pressor. This air is used for combus-tion as well as for cooling. A mid-size CT consumes huge amounts of air, around 500 to 1,000 pounds per second. Air is the friend of the CT; other mate-rials entering with the air are the en-

emy. The enemies includes particles of dust, airborne contaminants, and vola-tile (gaseous) substances. The CT has a very elaborate filtering system that is quite effective in stopping the entry of these unwelcomed enemies, but even the best system is at best 99% effective. Even at this high filtering level, contami-nants do get past the filters and must be dealt with downstream in the CT.

Efficiency is the watchword for CT owners. Efficiency is quite simply the percentage of useful work extracted from the fuel that is burned. The effi-ciency of a CT is strongly influenced by the mass-flow through the machine. In the air handling system, this desire translates into larger weight of air per unit volume. Essentially, the air must be denser, and colder air is denser so many air handling systems have features to cool the air such as evaporators, chillers, or foggers. These devices have benefits in efficiency, but can malfunc-tion and contribute to compressor or gas generator damage. Such damage usually comes in the form of erosion and corrosion in the compressor and hot corrosion in the gas generator.

Compressor The compressor is a critical piece of the combustion turbine system. It must take air at ambient conditions and highly compress it while maintaining the extreme volumetric flow. This air com-pression consumes energy from the fuel typically 50% to 70% of the CT gross output. The compression ratio (the outlet pressure divided by the ambient pressure) has a large impact on the CT efficiency. As the air is compressed, it also gets hot. Compressor discharge temperatures can be as high as 850oF.

The compressor also has to tolerate the inadvertent contaminants intro-duced with the inlet air. These con-taminants tend to concentrate in the compressor as the moisture evapo-rates, depositing the contamination on compressor surfaces. These contami-nants can lead to compressor corrosion and cause maintenance, inspection, and reliability issues. On some CT designs, there is very little margin for corrosion due to these deposits, and multiple compressor losses have been observed. Additionally, improper atomization of the water in a fogging system can also

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Figure 2. Fuel System.

degrade the blade surfaces, increasing the risk of compressor failure.

Compressor design is always a trade-off between maximizing efficiency and reli-ability. To be reliable the compressor should be robust. To be efficient the compressor designer wants long thin aerodynamically efficient blades at the expense of robustness.

Combustor The combustor is the section in which the compressed air from the compres-sor meets the fuel. When they meet, there is a controlled explosion that pro-duces the energy that drives the com-pressor via the turbine and the surplus energy is extracted other work. Com-bustors in CTs vary greatly. They can be nozzles that distribute the gas in a uniform pattern that is dispersed and mixed with air by small “fans” called swirlers. Alternatively, combustors can be complex, consisting of a series of se-quential, computer controlled burners to meet regulated environmental limits.

No matter what the design, the combus-tors have three basic functions: 1. They must mix the fuel and air com-

pletely so that complete combustion occurs.

2. They must balance the ratio of fuel to air to meet environmental require-ments.

3. They must deliver the combustion gases to the inlet of the gas genera-tor.

The engineering challenges in combus-tors are many but include choosing ma-terials, coatings, and design features that can survive the extremely high tempera-tures, as well as minimizing and tuning the acoustics caused by the controlled explosions of the fuel. The acoustics are often culpable in fatigue failures in the combustor.

Gas Generator The gas generator receives the super-heated, pressurized air and combustion gases from the combustor and passes this mixture over a series of rotating blades and redirecting vanes which ex-tract the heat and pressure from the gas stream. This thermal energy is then

converted into rotational energy that spins the rotor of the combustion tur-bine. While the technology of this ther-mal/pressure to mechanical energy transfer is well understood by engineers because of decades of experience with steam turbines, the challenge with CTs is the extreme temperature and environ-ment.

The efficiency of the turbine is very de-pendent on gas generator firing tem-perature. The higher the firing tempera-tures, are the more efficiently the ma-chine operates. The limits are the capa-bilities of the materials and the ability to cool the parts with compressor air. The extreme firing temperatures, pressure from gas flow, and centrifugal loads me-chanically challenge the gas generator materials. The environment is also de-structive from oxidation and high tem-perature corrosion. The materials used in the gas generator section are nickel or cobalt-based alloys referred to as superalloys. These materials are very resistant but not immune to the thermo-mechanical damage in the gas genera-tors. These components are also typi-cally coated with corrosion and oxida-tion resistant coatings that actually met-allurgically bond to the components to form ceramic-like thermal barrier coat-ings to further reduce metal heating from radiant heat. To further combat the thermo-mechanical damage, some parts are actually made using sophisti-cated processing that can directionally solidify and form single crystal parts. Not surprisingly, these parts can cost

upwards of $40,000 each. Considering that as many as ninety blades (and multi-ple vanes) are required for each turbine stage (usually with three or four stages) that translates to $3 million to $4 mil-lion or more per overhaul, depending on the size and complexity of the frame type.

Power Extraction System The power from the gas generator that is not used by the compressor provides useful energy to mechanical, thermal, or electrical drives and completes useful work. The power extraction systems can be boilers, power turbines, electrical generators, or other mechanical devices. The ultimate goal is to extract every calorie of energy from the gas generator output.

In a true jet engine, the energy from the gas generator provides thrust and mo-mentum to the aircraft. In a non-flight engine, this same thrust can be passed over a power turbine to generate me-chanical/rotational energy to drive a me-chanical device. Another energy scheme is to pass the hot gas exhaust into a steam boiler, usually called a heat recov-ery steam generator (HRSG). The resul-tant steam production is used to power a steam turbine.

Summary This short article provides an overview of combustion turbines. They are con-ceptually simple machines (which are complex or even exotic in execution) that challenge the materials and design technology of today.

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CORROSION 2010 will go down in history as the largest NACE Conference in a decade! This year more than 5,900 attendees from 60+ countries joined together in San Antonio, Texas, for the world’s largest corrosion conference and exposition. CORROSION 2010 was full of informational meetings, symposia, and forums, entertaining networking events, and an exhibit hall that featured over 550 exhibits from companies from around the world. NACE International would like to thank everyone for making this year a huge success. Catherine Noble attended CORROSION 2011, March 13 through March 17, 2011, in Houston, Texas.

Contact the Authors

Ron Munson, P.E., 512-407-3762 ron_munson@mmengineering.com

David Daniels, 512-407-3752 david_daniels@mmengineering.com

Max Moskal, 708-784-3564 max_moskal@mmengineering.com

Ron Lansing attended the HRSG User’s Group Meeting in Jacksonville, Florida April 13th and April 14th at the Hyatt Regency Jacksonville Riverfront.

New Employees Join M&M Engineering

Charlie Rutan joined M&M Engineering the latter part of April. His expertise is the Petro/Chemical industry. Mr. Rutan has consulted on turbomachinery, cold service high head pumps, hot tapping and plugging problems all over the world for Lyondell, Exxon/Mobil, Shell, DuPont, BP and others. He has published and/or presented articles for AIChE, ASME, Hydrocarbons Processing, NPRA, and Texas A&M International Turbomachinery Symposium. Mr. Rutan has provided, and continues to provide, internal mentoring to all engineering disciplines involved in plant operation, maintenance, reliability, and design.

Ken Layton joined M&M Engineering in April and is assisting with the chemical cleaning of boilers and water/ steam chemistry audits for our clients. Mr. Layton has worked for several large companies for

over thirty-eight years, including Bechtel Power Corporation, Jack K. Bryant and Associates, Utah Power and Light Company, PacifiCorp, Algon/Nalco Corporation in California and Utah. His expertise is in the water chemistry area, with emphasis on conducting chemistry audits and cleaning, training classes, and failure investigation/analysis of power plant components including boiler tubes, and steam cycle contamination.

Seminars and Workshops Attended

Jon McFarlen will be attending the Flow-Accelerated Corrosion (FAC) in Fossil and Combined Cycle/HRSG Plants International Conference, June 29, 2010, to July 1, 2010, in Arlington, VA.

Upcoming Events

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the Conduit is distributed free of charge by M&M Engineering Associates, Inc.. We welcome your comments, questions, and suggestions, and we encourage you to submit articles for publication. We grant limited permission to photocopy all or part of this publication for nonprofit use and distribution. For technical information, please contact:

David Daniels (512) 407-3761 david_daniels@mmengineering.com

Ron Munson (512) 407-3762 ron_munson@mmengineering.com

Karen Fuentes (512) 407-3778 karen_fuentes@mmengineering.com

Texas • Illinois • Oklahoma

www.mmengineering.com

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the Conduit M&M Engineering Associates, Inc. 4616 W. Howard Lane, Bldg. 2, # 500 Austin, TX 78728-6302