ASME Preventing Turbine Water Damage ASME Standard TDP-1

ASME Preventing turbine water damage ASME Standard TDP-1 By Larry Kielasa, John Boyle and Ram G. Narula | Posted: Tuesday, September 1, 2009 12:00 am

ASME: Preventing turbine water damage - ASME Standard TDP-1 Figure 3. Typical drain pot with redundant level elements With the advancements in combined cycle, steam generation and co-generation technology systems, ASME has published an updated version of its "Recommended Practices for the Prevention of Water Damage to Steam Turbines Used for Electric Power Generation - Fossil Fueled Plants," ASME TDP-1 2006. TDP-1 was originally published in 1972 and subsequently revised in 1979, 1985 and 1998. The new standard was rewritten to include combined-cycle configurations, multiple steam generator configurations and cogeneration technologies. The standard also was revised to address plant cycling and modern plant instrument and control systems. This article will summarize the major changes included in the updated standard. TDP-1 was initially developed in response to a rash of water induction incidents in the 1960s as power plants scaled up above 150 MW. TDP-1 now includes conventional steam (Rankine) cycle and Combined-Cycle power plants. Nuclear power plants are covered under TDP-2.

TDP-1 is a Recommended Practice and not a mandatory code - if you want the features put forth in TDP-1 to be included in your design standard, it must be invoked your contract. Water induction damage Water induction can damage steam turbines in several ways. The damage can be caused by the impact of large slugs of water or by the quenching effect of cold water on hot metal. The severity of water damage can vary from minor seal rubs all the way to catastrophic damage to the turbine. Generally, water damage falls into the following categories:  Thrust bearing failure  Damaged blades  Thermal cracking  Rub damage  Permanent warping distortion  Secondary effects Secondary effects include items such as seal packing ring damage, pipe hangar and support damage, damage to instrumentation and controls, etc. Sources of water induction Water can be inducted into a steam turbine from several sources. The following are some of the most common sources of water:  Motive steam systems  Steam attemperation systems  Turbine extraction/admission systems  Feedwater heaters  Turbine drain system

 Turbine steam seal system  Start-up systems  Condenser steam and water dumps (steam bypass)  Steam generator sources Figure 1 shows the percentage of water induction incidents attributed to the most common sources of water in conventional steam cycles. Although water induction into the high and intermediate pressure turbines has historically been recognized as the most damaging, experience has shown that water induction in low pressure turbines also can cause significant damage and should be taken seriously. Water induction can happen at any time; however the most common situations are during transients such as start up, shut down and load changes. Figure 2 illustrates the percentage of times various events contribute to water induction for a conventional steam cycle. It is interesting that only 18 percent of water induction incidents occur when the unit is at load. TDP-1 concepts TDP-1 offers guidance on how to identify systems that have the potential to allow water to enter the turbine and to design, control, maintain, test and operate these systems in a manner that prevents any significant accumulation of water. This is the first line of defense in preventing turbine water damage. However, it is recognized that malfunctions do occur, so TDP-1 offers recommendations for preventing turbine damage that include: detection of the presence of water either in the turbine or, preferably, external to the turbine before the water has caused damage; isolation of the water by manual or, preferably, automatic means after it has been detected; and disposal of the water by either manual or, preferably, automatic means after it has been detected. The philosophy of TDP-1 has been, and will continue to be, that "no single failure of equipment, device, signal or loss of electrical power should result in water or cold steam entering the turbine." What is new in TDP-1?

TDP-1 includes several new items that address recent industry experience. These include the addition of combined-cycle units and the application of modern control systems and technology to turbine water damage protection. The updated standard addresses the following:  Combined-cycle configurations such as High Pressure, Intermediate Pressure and Low Pressure drums on Heat Recovery Steam Generators (HRSG)  Cascading and direct turbine bypass systems  Recommendations for process steam lines associated with co-generation configurations  Recommendations on superheat attemperation at the outlet of the final superheater of HRSG  Additional clarification of system drain requirements, including the use of drain flash tanks and pumped condensate drain tanks Recommendations for draining side and axial turbine exhaust orientations into the condenser Integrated control systems (ICS), such as distributed control system (DCS), into closed and open feedwater heater level instrumentation and controls and expanded on the control and automation criteria for turbine water induction protection systems. To facilitate the discussion of combined-cycle configurations, TDP-1-2006 introduces the concept of motive steam. Motive steam systems are systems that supply steam to a steam turbine for the primary purpose of power production or to an auxiliary turbine, such as a boiler feed pump drive turbine. The committee introduced the concept of motive steam to incorporate combined-cycle configurations: HP, IP and LP drums, in addition to the existing conventional steam (Rankine) cycle configurations. Motive steam systems include:  Main steam  Hot and cold reheat steam

 High pressure (HP) steam  Intermediate pressure (IP) steam  Low pressure (LP) steam  Admission steam Motive steam systems do not include:  Extraction steam  Gland steam seal line Recommendations for combined-cycle configurations In this standard, a combined cycle is defined as a hybrid of the gas turbine (Brayton) and steam (Rankine) cycles. Waste heat contained in the gas turbine exhaust is fed through an HRSG that produces steam that is expanded through a condensing steam turbine to produce power. HRSG system configurations typically include as many as three steam drums, each with level controlled by feedwater valve modulation and condensate or feed pump recirculation, or similar method of controlling inflows. The same plant design requirements that apply to other steam generators apply to HRSGs. The use of attemperators external to the steam generator, downstream of the last superheating (or reheating) element, is discouraged; however, it is recognized that under some conditions it cannot be avoided. When this type of attemperator is required in the motive steam line to control the temperature of the steam entering a steam turbine, several additional features are recommended to provide adequate protection. When a gas turbine cooling steam or power augmentation steam pipe is connected to a motive steam line, this pipe should not be connected at or near the low point of the motive steam pipe. If routing of this pipe creates a low point, a drain should be provided from the pipe. Turbine bypass systems Turbine bypass systems should be provided with the same level of protection as motive steam piping.

These should include drains and drain pots (if applicable) with power-operated drain valves. Attemperators in bypass systems that discharge to the cold reheat system (or any other line connected back to the steam turbine) should be designed to the same requirements on motive steam system attemperators. Non-return valves should be provided in the cold reheat system to prevent the reverse flow of bypass steam into the steam turbine. Designers should carefully consider the location, design and orientation of large steam dumps (such as turbine bypasses) into the condenser. Process (co-generation) steam Process steam lines that are supplied from motive and extraction steam lines are a potential source of water induction. Motive and extraction steam lines should be protected from process steam lines with the following features:  Two power-operated block valves should be provided to isolate the motive steam or extraction steam line from the process steam line. Any two of the following are acceptable:

1. A pressure-reducing valve (control valve) with Fail-Closed capability (capable of closing against the maximum reverse differential pressure) 2. A power-assisted non-return valve 3. A standard power-operated block valve  The designer should consider steam supply and process system upsets that might result in cold steam admission to the motive/extraction steam line.  If an attemperator is required, it should be located downstream of the second power operated block valve. Recommendations for steam line drains Drain location and types There are three types of steam line drains:  Standard with power operated block valve

 Drain Pot with power operated block valve  Drain Pot with redundant level elements and power operated block valve Figure 4 shows a typical drain pot with redundant level elements. This configuration is typically used in "high risk" areas. One change in this standard that is shown is the level sensing device, which is labeled as a level element (LE). In past versions of the standard, this device has been shown as a level switch. In the revised version, the level element can be a level switch, a thermocouple or a conductivity probe. Drains should be installed at each low point in the motive steam piping. Drain Pots are recommended at the following locations to enhance condensate collection:  Cold reheat line at first low point downstream of the steam turbine exhaust. (This application requires redundant level elements.)  Motive steam lines that operate (admit steam to the steam turbine continuously) with less than 100°F (56°C) superheat unless a continuous drain has been provided. (This application requires redundant level elements.)  Motive steam lines with attemperators - e.g. attemperator in HP steam line. The drain pot should be between the attemperator and the steam turbine. (This application requires redundant level elements.)  Motive steam lines that are prone to water accumulation during operation, for which large drain collection areas and/or water detection devices are desired.  Motive steam lines that will be under vacuum during steam turbine start-up and shutdown.  Branches and legs that will be stagnant during various operating modes, unless a continuous drain has been provided.  At the steam turbine end of long horizontal runs (more than 75´). Automatic drain control systems

As plant structures become more complex and a larger number of drains are involved, plants are adding automatic controls to simplify operation. Any automatic control system used to control steam line drain valves identified in this Standard should be designed so that the system has a means of initiating automatic valve actuation and a separate means of verifying the appropriateness of the automatic action. If an inappropriate action is taken, an alarm should be provided. For example, if a drain valve is closed automatically based on a timer, something other than the timer - such as a level element that would alarm if water were still present in the steam line - should be used to verify that the timer initiation was appropriate. Condensate drains tanks A typical condensate tank is shown in Figure 5. Critical issues include vent sizing, redundancy of controls and redundancy of pumping equipment, including independent power supplies. The following recommendations apply:  The cross-sectional area of the drain tank vent should be large enough to make certain that the tank internal pressure, with all simultaneous drains open, will be lower than that of the lowest pressure drain into the tank under all operating conditions, including start-up and shutdown.  When the drain tank is connected to the condenser, the drain tank should provide separation of entering condensate and steam from the drain source(s). The vent line to the condenser should be large enough so that the tank pressure will be less than the source pressures of all drains connected to the tank under all conditions. Under startup and shutdown conditions, some of the drains might be close to condenser pressure.  The tank drain line should be sized for the maximum service conditions. When a drain pump is required, it should be actuated automatically based on drain tank level. If a drain pump is required and its failure could possibly lead to water entering the turbine, redundant drain pumps (supplied with power from separate power sources) should be furnished, each controlled by an independent level controller actuated automatically based on drain tank level. Independent level signals indicating a high-high alarm condition in the tank should be provided in the control room.

 Connections for incoming drains on the tank should be located above the maximum water level in the tank. Axial or side turbine exhaust  Avoid discharging high-energy bypass steam into the area between the condenser hotwell and the tube bundle  Locate the curtain spray and bypass sparger a safe distance from the condenser tube bundles to allow a sufficient reduction in kinetic energy, so that high-energy steam does not reach areas above and below the tube bundles and cause a recirculation backflow with entrained water toward the turbine.  Determine an incidence angle of high-energy steam jets that will avoid reflected velocity vectors toward the turbine exhaust. Integrated control systems (ICS) In the standard, an integrated control system (ICS) is defined as, "a control system featuring multiple processors, input/output (I/O) modules and memory storage interconnected through a communication network and equipped with redundant power supplies. Normally, a distributed control system (DCS) or redundant programmable logic controllers (PLCs) will meet this requirement." The minimum ICS features to meet the reliability and redundancy needs addressed in this standard are:  Dual processors  Uninterruptible power supply  I/O associated with redundant plant equipment, and that instruments should not be connected to the same I/O cards.  Outputs that fail to know position during processor or internal communication failure. Conclusion

TDP-1-2006 was revised to include recent experience, modern instrumentation and technology and combined-cycle systems. The overriding philosophy remains constant: "No single failure of equipment, device or signal, or loss of electrical power, should result in water or cold steam entering the turbine." The Committee is currently working on TDP-2 for nuclear power plants. Look for it in the near future. This article was published with permission of the ASME Power Division. For more information, visit www.asme.org. Larry Kielasa is presently retired after serving 38 years with DTE Energy. During his career, Kielasa served in a variety of engineering and management roles. He is a past chair of the ASME Power Division, and is the current vice president of Financial Operations at ASME and chairman of the ASME Turbine Water Damage Prevention Committee. He has a bachelor's degree in Nuclear Engineering from the University of Michigan and a master's degree in Administration from Central Michigan University. You may contact him by e-mailing [email protected]. John Boyle is a senior engineering technical specialist at FM Global, a business property insurer, where he works with companies in the power generation industry to help protect their facilities from property-related risks. He is a member of the ASME Turbine Water Damage Prevention Committee. He has a bachelor's degree in Engineering Science and a master's degree in Chemical Engineering from the University of Rhode Island. You may contact him by e-mailing [email protected]. Ram G. Narula has more than 48 years of experience in the power industry, including 37 years with Bechtel Power Corporation, where he is vice president and chief technology officer. He is a Fellow of the ASME International and the Vice Chair of the ASME Turbine Water Induction Prevention Committee. Narula served on the ASME Codes & Standards Board of Directors for 8 years. He has a B.S. degree in Mechanical Engineering, an M.S. degree in Nuclear Engineering, and an M.B.A. degree. He has published more than 100 technical papers and traveled to more than 60 countries. You may contact him by e-mailing [email protected].