STANDARD ANSI/ISA–77.14.01-2010 Fossil Fuel Power Plant Steam Turbine Controls Approved 10 November 2010 ANSI/ISA–77.14.01-2010 Fossil Fuel Power Plant Steam Turbine Controls ISBN: 978-1-936007-67-7 Copyright 2010 by ISA. All rights reserved. Not for resale. Printed in the United States of America. No part of this publication may be reproduced, stored in a retrieval system, or transmitted, in any form or by any means (electronic, mechanical, photocopying, recording, or otherwise), without the prior written permission of the Publisher. Copyright 2010 ISA. All rights reserved. ONE OR MORE PATENT HOLDERS OR PATENT APPLICANTS MAY HAVE DISCLOSED PATENTS THAT COULD BE INFRINGED BY USE OF THIS DOCUMENT AND EXECUTED A LETTER OF ASSURANCE COMMITTING TO THE GRANTING OF A LICENSE ON A WORLDWIDE. in the preparation of instrumentation standards. the editions indicated were valid. recommended practices. O. constitute requirements of this document. symbols. 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Chair Wayne Holland Sergio Alvarez Drake Bosler Byron Broussard Gary Cohee Alan Davison Dudley Foreman Andrew Gavrilos Robert Hubby Goray Mookerjee James Olson Philip Reeves Michael Skoncey Stephen Sykes Cyrus Taft Joseph Vavrek COMPANY Wood Group TCS CH2M Hill Compania Inspeccion Mexicana Consultant Turbomachinery Controls Solutions LLC Applied Control Systems Fluor Canada Ltd. IF ANY. Christopher G. Holland COMPANY Emerson Process Management Israel Electric Corp. OR DETERMINING WHETHER ANY LICENSING TERMS OR CONDITIONS PROVIDED IN CONNECTION WITH SUBMISSION OF A LETTER OF ASSURANCE. Batug D.ANSI/ISA–77. Gavrilos J. THE USER MUST ALSO CONSIDER THE APPLICABILITY OF ANY GOVERNMENTAL REGULATORY LIMITATIONS AND ESTABLISHED SAFETY AND HEALTH PRACTICES BEFORE IMPLEMENTING THIS STANDARD. Sargent & Lundy LLC The following people served as voting members of ISA77: NAME G. Gilman W. Cohee D. OR EQUIPMENT.14. McFarland. THE USE OF THIS DOCUMENT MAY INVOLVE HAZARDOUS MATERIALS. Hocking W. Consultant Consultant Tennessee Valley Authority Luminant Power First Energy Generation Corp. THE USER OF THIS DOCUMENT MUST EXERCISE SOUND PROFESSIONAL JUDGMENT CONCERNING ITS USE AND APPLICABILITY UNDER THE USER’S PARTICULAR CIRCUMSTANCES.* JFG Technology Transfer LLC Invensys Process Systems* CH2M Hill Copyright 2010 ISA. PPL Generation LLC Consultant Applied Control Systems Invensys Foxboro* Hitachi Power Systems America ABB Inc. OR IN ANY LICENSING AGREEMENTS ARE REASONABLE OR NON-DISCRIMINATORY. ISA REQUESTS THAT ANYONE REVIEWING THIS DOCUMENT WHO IS AWARE OF ANY PATENTS THAT MAY IMPACT IMPLEMENTATION OF THE DOCUMENT NOTIFY THE ISA STANDARDS AND PRACTICES DEPARTMENT OF THE PATENT AND ITS OWNER.01-2010 –4– INQUIRIES INTO THE LEGAL VALIDITY OR SCOPE OF PATENTS. Power Consultants ABB Inc.14: NAME Jeffrey Schleis. Invensys Process Systems Taft Engineering Inc. All rights reserved. Crow R. The following people served as voting members of Subcommittee ISA77. Altcheh J. THE DOCUMENT CANNOT ANTICIPATE ALL POSSIBLE APPLICATIONS OR ADDRESS ALL POSSIBLE SAFETY ISSUES ASSOCIATED WITH USE IN HAZARDOUS CONDITIONS. Managing Director L. Eng A. . Tatera I. Icayan J. Ametek. Honeywell International. Maggioli T. Tatera & Associates. Inc. Inc.01-2010 R. Gilsinn E. Reimer N. Olson P. IC Engineering ABB Inc. Lee G. Dunn R. Reeves D. Hubby Consulting Bechtel Power Corp. Weidman J. Yokogawa IA Global Marketing Emerson Process Management Copyright 2010 ISA.14. Taft A. Schnaare J. The Dow Chemical Co. Kaufman K. Hubby H. Schneider Electric Aramco Services Co. Consultant This standard was approved for publication by the ISA Standards and Practices Board on 10 November 2010. All rights reserved.* Detroit Edison Co. McAvinew A. Dunn J. Inc. Inc. Zadiraka Robert N. Sands H. Endress+Hauser Process Solutions AG Feltronics Corp. Wilkins M. Industrial Automation Networks. Inc. EnCana Corporation Ltd. Roney M. Tennessee Valley Authority Luminant Power URS-Washington Division First Energy Generation Corp. Coppler E. Johnson D. Jamison D. . ICS Secure LLC Consultant Applied Control Solutions LLC Kahler Engineering. DuPont Engineering NIST/MEL ACES Inc. Rosemount. Mookerjee J. Stevenson C. Zielinski COMPANY Honeywell Inc. Sasajima T. Inc. Verhappen R. Inc. Rockwell Automation DuPont Yamatake Corp. Cosman B. Dumortier D. Widmeyer M. NAME P Brett M. Lindner V. McCauley R. Jacobs Engineering Chagrin Valley Controls. Webb W. Johansen R.–5– ANSI/ISA–77. Skoncey T. Constellation Energy Taft Engineering Inc. Weiss M. ANSI/ISA–77. All rights reserved. .14.01-2010 –6– This page intentionally left blank. Copyright 2010 ISA. 5. 4. 4. Scope Purpose Definitions Design requirements Instrumentation Overspeed trip system Turbine control system design Turbine control system functions Operator interface Training 9 9 9 12 12 13 13 14 22 24 Copyright 2010 ISA.–7– ANSI/ISA–77.1.14. 4. 2. 5. 4.01-2010 CONTENTS 1. 4.2. 4. . 3.4.3. All rights reserved. 14.ANSI/ISA–77. .01-2010 –8– This page intentionally left blank. Copyright 2010 ISA. All rights reserved. First-stage pressure is also referred to as impulse pressure by some turbine manufacturers.6. Copyright 2010 ISA. Controller: Any manual or automatic device or system of devices used to regulate processes within defined parameters.3.–9– ANSI/ISA–77. Definitions The following definitions are included to clarify their use in this standard and may not correspond to the use of the word in other texts: 3. and sensing devices. and turbine water induction prevention (TWIP) systems. Distributed control system (DCS): A digital control system in which the control computations are performed on multiple processing units. The pressure at this point is closely proportional to the flow rate of steam through the turbine. 3. 3. automated startup/shutdown systems.1. 3. First-stage pressure: The pressure within a steam turbine at the point where the steam exits the first row of turbine blades. . control processor(s). Control valve: A valve or set of valves used to regulate inlet steam flow to the turbine during normal operation and controlled by the turbine control system. 2.5.4.2. 3. Specifically excluded from consideration are single valve and controlled extraction turbines. Full arc: Steam admission that throttles steam equally through all nozzle segments or partitions simultaneously. mechanical drive turbines. Decision-making equipment with its associated power supplies. 3. I/O hardware. Emergency condition: Any condition that requires operator or control system intervention to prevent personal injury or equipment damage. turbine supervisory instrumentation. Failsafe: The capability to go to a predetermined safe state in the event of a specific malfunction.8.9. Fault tolerant: Built-in capability of a system to provide continued correct execution of its assigned function in the presence of one or more hardware and/or software faults. Purpose The purpose of this standard is to establish the minimum requirements for functional design specifications of steam turbine control systems for use in fossil fueled power generation plants. Scope This standard addresses steam turbine governor controls and overspeed protection of steam turbine generators in fossil power plants.7.01-2010 1.14. All rights reserved. 3. 3. See partial arc. 3. Bumpless transfer: Automatic tracking such that any control mode transfer is accomplished without a sudden process upset. steam bypass systems. 3. .11.14. Restricted access parameter: A parameter within the turbine control system to be adjusted or tuned by qualified personnel with restricted access and not modified as part of normal operation.21. 3. Linear variable differential transformer (LVDT): A form of position measurement made by varying the inductive coupling (core rod position) between the primary and secondary windings of a transformer. Initial pressure regulator (IPR): A device or function that modulates the control valves closed on loss of inlet pressure. the intercept valves are used to regulate steam flow during startup.15. The intercept valves are an integral part of the overspeed protection system and.18. Copyright 2010 ISA. Overspeed: Any speed above rated synchronous speed. 3. Governor valve: See control valve. Reset: An action taken to prepare the turbine for startup. 3. Operator parameter: A parameter within the turbine control system accessible from an operator console by anyone with operator access rights.22.12.23. 3. 3. Load control: Control of generator output power while the generator breaker is closed.20. Inlet pressure: Pressure immediately upstream of the throttle valve(s). See full arc. 3.17. Impulse pressure: See first-stage pressure. 3. 3. 3.13.14. This is also sometimes referred to as latching the turbine. Load limiter: A device or function that limits turbine flow and therefore limits the power generated by the turbine.10. All rights reserved. 3.16. In some applications.ANSI/ISA–77. Partial arc: Steam admission that does not throttle steam equally through all nozzle segments or partitions. depending on the turbine manufacturer. Main steam pressure: See inlet pressure.01-2010 – 10 – 3.19. may be of the modulating or open/closed design. 3. Inlet pressure is also referred to as main steam pressure or throttle pressure by some turbine manufacturers. Intercept valve: A valve or set of valves in position to regulate steam flow from the reheater to the IP turbine. 3. 3. Stop valve: A valve or set of valves used to shut off steam flow to the turbine during turbine shutdown. phase. these valves are used to regulate steam flow during startup. See partial arc. Throttle pressure: See inlet pressure. 3. and voltage between the turbine generator and the utility grid to allow proper breaker closure. Turbine control system (TCS): Decision-making equipment with its associated power supplies. I/O hardware. 3. Copyright 2010 ISA. 3.– 11 – ANSI/ISA–77. 3. Valve position limiter: See load limiter. 3. 3. This can occur as a result of an emergency condition or as part of a normal shutdown.28. the word “SHOULD” as a STRONG RECOMMENDATION. In some applications.30.36. 3.31. control processor(s). 3.32. Runback: An action initiated by the loss of selected auxiliary equipment. Single-valve mode: Control valves opening simultaneously. 3. Sequential valve mode: Control valves opening in a sequence. All rights reserved.35. 3.14.34. Throttle valve: See stop valve. Synchronization: The process of matching frequency. Speed droop is inversely proportional to the steady-state gain of the speed controller. 3. 3. Trip: An action where all of the steam turbine valves are closed as quickly as possible.01-2010 3. Speed control: Closed-loop control of turbine speed (RPM) before synchronization. in which the load is reduced automatically to a level which can be sustained with the remaining auxiliary equipment.27. Shall and should: The word “SHALL” is to be understood as a REQUIREMENT. The stop valves are tripped closed by the turbine protection system. . and sensing devices that monitor and control the turbine. 3.29. Speed droop: The ratio of the percentage speed change to the resulting percentage valve-position change.26.24.25. one or more valve(s) opening following another. See full arc.37.33. Rundown: An action initiated by an undesirable operating condition. in which the load is reduced until the undesirable condition has cleared. 1. Valve position control: A control mode in which the load demand is directly translated into valve position demand without closed loop load feedback within the turbine controller. 4. All rights reserved. reheat stop (ZT103).Turbine instrumentation (typical) PT 101 ZT 101 ZT 102 H Stop Valve H Control Valve PT 102 JT 101 ST 101 ST 102 ST 103 HP IP LP Generator Intercept Valve ZT 104 Reheat Stop Valve Condenser ZT 103 Re-heater 4. 103). .Error! No text of specified style in document.2.01-2010 – 12 – 3. Instrumentation Process-sensing devices (see Figure 4. Design requirements 4.38.2). Limit switches are acceptable for valves whose position is not modulated. At least one of these speed probes shall be capable of reading turning-gear speed. An additional installed spare-speed probe should be supplied.1.1. Speed sensing A minimum of three speed-sensing devices (probes) shall be used for speed control (ST-101. LVDTs or similar measurement devices shall be used for modulating valves.Turbine instrumentation) should be installed as close as practical to the source of the measurement with appropriate design to prevent excessive vibration and temperature and to provide access for periodic maintenance.1 . Figure 4. control (ZT102). and intercept valves (ZT104). the speed probes used by the turbine control system shall be independent of those used by a backup electronic overspeed trip system.ANSI/ISA–77. Separate isolation valves and impulse lines should be run to each pressure-sensing device used for control. Valve position Feedback shall be instrumented for all valves controlled by the turbine control system: stop (ZT101).Error! No text of specified style in document.1 . 102. 4. However.1.14. Copyright 2010 ISA. When the backup overspeed trip system is an electronic design (refer to section 4. some turbine valve actuators may require a closed loop positioning system. input or output hardware.1. Generator Megawatt transducer (JT-101). The failure behavior of components shall be considered and incorporated in the design. First-stage pressure transmitter (PT-102).3. API 670. Diagnostics The control system design shall include diagnostics to monitor and alarm any component failures. A multi-toothed surface for speed sensing shall be provided integral with or securely attached to the turbine shaft. and a tachometer shall be permitted. The backup overspeed trip system shall be capable of tripping the turbine without the involvement of the turbine control system. Generator breaker status 4. Turbine trip status Typically a pressure signal on the trip oil header.– 13 – ANSI/ISA–77. T/Cs.1.4. the backup system shall be either a mechanical overspeed trip device or an electronic overspeed trip system as defined by the American Petroleum Institute standard. Copyright 2010 ISA.3. Turbine control system design 4.5.14. 4. Architecture The turbine control system design should be fault tolerant. RTDs. . Details of the speed sensing measurement shall follow API 670. 4.1. when utilized as the backup system for the overspeed trip function.3. Steam pressures Inlet-pressure transmitter (PT-101). All rights reserved.1.01-2010 4. shall perform the trip function through independent solenoids. The turbine control system and the electronic overspeed trip system. etc. data transfer. Sharing this surface between the turbine control system. The turbine control system shall be designed to be failsafe. 4. Speed sensing devices (probes) used by the turbine control system shall be independent of those used by a backup electronic overspeed trip system. Diagnostics shall be included to monitor and alarm any analog input (4-20mA.3. a backup electronic overspeed trip system. and power supplies. 4. Overspeed trip system Two independent turbine overspeed trip systems shall be provided: The primary system shall be within the turbine control system.1.) signal failure.1.2. The turbine control system functions shall reside in a dedicated controller that is segregated from other plant functions. including: processor. 2.4. Speed-sensor voting shall switch from median-signal to high-signal select if a speed-sensor fault condition exists. generator load.1. The data update period for data archival shall not exceed 1 sec. Reset of the turbine is a prerequisite to complete the reset sequence before attempting speed control.4. The turbine control system shall include interlocks to ensure valves open in a sequence in accordance with the OEM design. first-stage steam pressure. Turbine reset Once all of the trip conditions have been cleared. 4. the speed control setpoint shall be automatically set to no greater than the current turbine speed. Upon confirmation the turbine is reset (turbine trip status input cleared).16 for a definition of possible steam admission modes based on OEM design.4. all steam admission valves that are not used to control speed for the selected steam admission mode shall ramp open. Data archival Archival of turbine control system data is used for performance analysis and not intended for sequence of event analysis. The minimum data to be archived include: a) b) c) d) e) f) g) h) turbine speed. 4. 4.3.14. and trip-system status.3. active control mode. controller outputs. Tunable values and parameters shall have restricted access.ANSI/ISA–77.4. All rights reserved.3.2. the operator shall be able to initiate a reset of the turbine. When this occurs. Normal range speed control The turbine speed control described in this section shall provide closed-loop speed control from zero speed through rated speed when the main generator breaker is open.01-2010 – 14 – 4. Copyright 2010 ISA. Security Changes to the turbine control system’s logic shall be protected from unauthorized access. Refer to Section 4. The speed control system shall use a median-signal select of the three speed sensors. The turbine control system shall automatically transfer to speed control mode when the turbine is initially reset and when the other speed control permissives are satisfied. Turbine control system functions 4. . inlet steam pressure. valve positions. The input from the external system shall be limited by the TCS to reasonable ranges and rates and shall be either a hardwired input or a digital data interface with a data update period not to exceed 500 msec. Activation of online testing functions shall have safeguards to prevent inadvertent operation. power-load unbalance) that require additional measurements (e. the turbine control shall initiate a step change in flow demand to establish load on the generator. there may be several additional overspeed protection functions (e.14. Implementing the ramp as an operator function within predefined limits shall be permitted. this function shall have no further action.4. A means of testing and verification of all overspeed trip systems shall be provided. A method shall be implemented to prevent turbine speed from operating continuously in a critical vibration window. The speed controller shall provide stable control at all times and regulate within plus or minus one RPM of setpoint during steady speed conditions. if necessary. reheat pressure and generator current). and the speed setpoint at that time shall be the rated speed of the turbine. The operator shall have the capability of ramping the speed control setpoint at a minimum of three selectable rates expressed in RPM/min. This demand input shall be separate from the operator speed control inputs in order to allow different gains. The turbine control system shall assume speed control of the turbine when the generator breaker opens.4. The overspeed trip setpoint shall be a restricted access parameter.01-2010 After the turbine is reset. from an automated turbine startup system). Initial megawatt pick-up Upon generator breaker closure. On turbines where a steam admission valve transfer occurs before rated speed is reached. pre-emergency governor. to test the backup overspeed trip system. All rights reserved.g. Copyright 2010 ISA.4. The speed controller shall provide at a minimum the equivalent of proportional plus integral control action.g. 4. Initial megawatt pick-up settings shall be restricted access parameters. the turbine control system shall control turbine speed to maintain an operator adjustable setpoint in RPM. . Overspeed functions The overspeed functions included in the turbine control system shall use the same speed sensors as the normal range speed control. After load is established. An overspeed trip condition shall be sensed by two out of three voting of the three speed sensor circuits from the normal range speed control signal. The turbine control system shall accommodate an external speed setpoint function (e.5. 4. This action shall be a step function and is not subject to the loading rate. Based on the unit size and turbine OEM. A failed speed sensor circuit shall be voted as an overspeed condition for that sensor.– 15 – ANSI/ISA–77. This functionality shall be incorporated into the control system design. the speed control system shall be designed to accomplish this transfer with an upset to the actual turbine speed of less than one percent of rated speed. This type of control ensures zero speed error under steady-state conditions. These parameters shall be implemented as a function of inlet steam pressure. 4. load-drop anticipator. limits.g. The turbine control system shall have provisions. and permissives. Synchronization The turbine control system shall be capable of receiving demand signals for speed setpoint changes during synchronization.3.4. Isochronous control mode Isochronous control is an optional function but subject to the following when provided: • Isochronous control shall be used when the generator breaker is closed. The upper limit shall be calculated based on the turbine OEM loading design limits. All rights reserved. Load limiter function The load limiter function shall limit the maximum flow demand to the turbine. it shall be adjustable by the operator and expressed in the same units as the open-loop load control.9. When the unit is tied to the grid. 4.4. The proportional control setting.4.9. Implementing loading rate as an operator function within predefined limits shall be permitted. This is the prevailing control mode while the generator breaker is closed unless a closedloop control mode is in service.8. is defined such that 5% regulation will mean that a 5% error in turbine speed will cause 100% travel of the turbine valves.4.4. the operator shall not be able to select any load-control mode. Speed droop Speed droop shall be enabled when the turbine/generator unit is connected to an electrical grid in parallel with other turbine/generator units.10 RPM. Speed droop shall be proportional-only control.4. The purpose of speed droop is to enhance grid stability and allow the turbine control system to respond to changes in bus frequency without operator intervention. Open-loop load control The transition from speed control to open-loop load control shall be automatic at the time the generator breaker closes.ANSI/ISA–77. . and speed droop shall be utilized as described in Section 4. The operator adjustable setpoint shall equate to turbine flow demand. There shall be an allowable speed error deadband. The regulation value shall be adjustable from 2% to 10%. called regulation. The load limiter shall take priority over all control modes.7. and the unit is independent of the grid. Isochronous control shall be a proportional-plus-integral type of control that maintains turbine speed at the setpoint. Load reference shall be implemented with no closed-loop control feedback signals and shall include an operator adjustable setpoint expressed in percent or megawatts. The specific setting shall be in accordance with the authority having jurisdiction. The deadband shall be a restricted access parameter adjustable between 0 and +/. In this situation. This function operates in addition to and not instead of the load limiter function.6. • 4. Some suppliers also provide a high.and low-load limit on the open-loop load control reference and/or the closed-loop megawatt control setpoint. which is an electronic descendant of the load limiter function traditionally provided with a mechanical governor system.01-2010 – 16 – 4. 4. isochronous control is not allowed. The turbine control system shall provide the capability of ramping the open-loop load control setpoint at a minimum of three operator selectable rates expressed in percent/min or megawatt/min. Copyright 2010 ISA. The specific setting shall be in accordance with the authority having jurisdiction.14. typical with automatic dispatch. All rights reserved.10. The remote load control mode shall have the capability to interface with the available signal type from the load control system. pulse frequency. shall be provided to the unit load master to coordinate steam generation. The turbine control system shall provide an operator adjustable setpoint in megawatts and a controller to maintain that setpoint. Closed-loop megawatt control Closed-loop megawatt control is an optional function but subject to the following when provided: • • The megawatt signal shall be either a hardwired or digital data interface with a data update period not to exceed 500 msec.01-2010 Figure 4.4. . or load limiter) to be controlled by an external system. An alarm shall be initiated any time speed droop exceeds the deadband and is active.14. This type of control ensures zero load error under steady-state conditions. open-loop load demand. Remote load control The turbine control system shall provide at least one remote load control mode that enables a turbine load reference (i. The closed-loop megawatt controller shall be at a minimum the equivalent of proportional-plus-integral control action.11. This alarm. Typically these are either discrete raise/lower inputs or a continuous analog value input either as a hardwired input or a digital data interface with a data update period not to exceed 500 msec. or other control system.2 – Speed droop curves for 5% regulation The output of the speed droop function shall include a first order lag function with an adjustable time constant from 0 to 10 seconds.4. When the remote signal is implemented via discrete raise/lower inputs. Copyright 2010 ISA.– 17 – ANSI/ISA–77. unit load master. MW setpoint. Speed droop settings shall be restricted access parameters. the turbine control system shall be capable of pulse width. along with the current load demand. 4. and pulse counting modulation.e. 4. This would typically be used to interface with an automatic load dispatch system. 5.12. If the failure occurs while this control is active. Failure of the impulse pressure control signal shall prevent this control from being put in service by the operator.4. the control system shall automatically take this function out of service. there shall be predefined limits. All rights reserved. The inlet pressure control shall have at a minimum the equivalent of proportional-plus-integral control action. first-stage (impulse) pressure control Closed-loop.14.2 for controller modes. the control system shall automatically take this function out of service. • • 4. See Section 4. first-stage pressure control shall be required when the turbine valve configuration allows for automated valve testing or steam admission valve transfers and is subject to the following when provided: • • The first-stage pressure signal shall be either a hardwired signal or a digital data interface with a data update period not to exceed 250 msec.14. The second method ramps the turbine back until the inlet pressure recovers but then holds that value as the load reference has tracked down during the upset condition.2 for controller modes. See Section 4. Copyright 2010 ISA. Placing the closed-loop. Close-loop inlet pressure control Closed-loop inlet pressure control is an optional function but subject to the following when provided: The inlet pressure signal shall be either a hardwired signal or a digital data interface with a data update period not to exceed 250 msec.ANSI/ISA–77. . The first method ramps the turbine back until inlet pressure recovers and then allows the turbine to ramp back to its original level prior to the upset condition. Initial pressure regulator (IPR) Initial pressure regulator shall be implemented to accommodate either of two methodologies. If the failure occurs while this control is active.4. 4. This type of control ensures zero pressure error under steadystate conditions. first-stage pressure control shall provide a controller to maintain first-stage pressure to the setpoint value. first-stage pressure control in and out of service shall be a bumpless transfer. Placing the closed-loop megawatt control in and out of service shall be a bumpless transfer.01-2010 • – 18 – The operator shall have the capability of ramping the megawatt control setpoint at a minimum of three selectable rates expressed in percent/min or megawatt/min. If the failure occurs while this control is active.2 for controller modes.5. • • 4. If the loading rate is implemented as an operator adjustable function. It shall have at a minimum the equivalent of proportional-plus-integral control action. An operator adjustable setpoint shall be provided in inlet steam pressure units and shall provide a controller to maintain setpoint.13.4. the control system shall automatically take this function out of service. Failure of the inlet pressure signal shall prevent this control from being put in service by the operator. This type of control ensures zero pressure error under steady-state conditions.5. See Section 4. Placing the closed-loop inlet pressure control in and out of service will be a bumpless transfer. Failure of the megawatt control signal shall prevent this control from being put in service by the operator. Closed-loop. The upper limit shall be calculated based on the turbine loading design limits. Closed-loop. When initiated. A command to initiate a runback or rundown shall be either a hardwired signal or a digital data interface with a data update period not to exceed 500 msec. Runbacks and rundowns A minimum of one turbine runback and one turbine rundown shall be provided. An alarm shall be generated if initial pressure regulator becomes active. or is disabled for any reason.16. .– 19 – ANSI/ISA–77. 4.4. Depending upon turbine control valve configuration. this transfer will result in either fullarc or partial-arc operation. When initiated. the transfer from stop to control valves can be prior to or after synchronization. the rundown will continue until the threshold is reached or the initiating condition is cleared. Stop valve to control valve Depending upon turbine design. the runback will continue until the threshold is reached. is selected out of service. the fastest rate shall prevail.5.1. The initial pressure regulator shall be initiated when inlet pressure drops below setpoint or when inlet pressure decreases at a high rate. 4. Steam admission control Steam admission control defines the sequence of operation for each type of turbine valve. Each runback and rundown will generate its own alarm. Copyright 2010 ISA. A deadband for initiating and clearing the IPR function shall be provided to prevent continuous initiating of the IPR function when operating around the setpoint. the turbine control system shall include logic to disable the turbine control system’s runback and rundown feature while the remote load control mode is in service. Each rundown provided shall have its own dedicated lower threshold and rate. An alarm shall be generated when a runback or rundown is initiated. the fastest rate shall prevail. The setpoint shall be either fixed or adjustable by the operator. The permissives to enable the transfer shall match the OEM requirements. a rundown overrides the current mode of operation and lowers the unit demand. The deadband amount shall be a restricted access parameter.14. the control system shall automatically take this function out of service. Once initiated.2 for controller modes. The operator shall also have the ability to place this control loop in or out of service. Failure of the inlet pressure control signal shall prevent this control from being put in service by the operator. When the turbine control system interfaces to an automatic load dispatch system. If more than one runback is initiated at a time.4. and the transfer shall be operator-initiated and/or automatically initiated. The initial pressure regulator shall include a method of preventing the unit from ramping to a zero load setpoint. If more than one rundown is initiated at a time. Once initiated. The following section describes the common sequences for various OEM designs.4. Each runback provided shall have its own dedicated lower threshold and rate.16.01-2010 The inlet pressure signal shall be either a hardwired signal or a digital data interface with a data update period not to exceed 250 msec. If the failure occurs while this control is active. See Section 4. All rights reserved. 4.15. a runback overrides the current mode of operation and lowers the unit demand. unit load master or other control system that has implemented turbine runbacks and rundowns as part of the remote demand signal. During a transfer. and the stop valves are modulating to maintain speed or load. Any transfer shall be reversible. the transfer shall be based on speed. the stop valves are ramped open until the control system determines the stop valves are governing steam flow. Testing shall be initiated by operator action. An operator shall be notified when an automatic transfer is initiated.4. Additionally. When the transfer is initiated automatically. 4. Before a transfer occurs. The turbine design will dictate which test functions are possible.16. all other load control functions shall be active. The ramp rate shall be a restricted access parameter.4. or to halt the transfer. Valve testing Steam-valve test functions shall be a part of the turbine control system. The transfer shall be operator-initiated and/or automatically initiated while the generator breaker is closed. Single to sequential Single-to-sequential valve transfer applies to turbines designed to have individual actuation of the control valves. The operator shall be able to halt the test momentarily or cancel a test at any time. such as runbacks and load changes. When testing control valves. a control valve position permissive shall be included to prevent the transfer occurring with the control valves open above this value. The transfer is complete when the control valves are modulating to maintain speed or load. When the transfer is initiated automatically.01-2010 – 20 – Before a transfer occurs. The permissives to enable the transfer shall match the OEM requirements and shall be initiated by the operator. permissives shall be included to ensure the turbine control system can compensate for the loss of steam flow during the test. control-valve testing shall only be allowed when the generator breaker is Copyright 2010 ISA. the unit shall start in the single mode. The transfer ramp times shall be adjustable to minimize the upset caused during the transfer. The transfer ramp rates shall be restricted access parameters. and the intercept valves are modulating to maintain speed or load. The transfer is complete when the stop valves are modulating to maintain speed or load. load. the stop valves are closed. or valve position. To minimize the upset during the transfer. When this function is possible. This value shall be a restricted access parameter. During the transfer.3.14. Intercept valve to stop valve Some turbines provide for a hot-start capability where the turbine is started on the intercept valves requiring an additional transfer from the intercept valves to the stop valves.4. This allows operation of the control valves together with one demand signal (single) or staggered in operation (sequential). This includes both modulating and non-modulating valves. At this point the intercept valves are ramped open. the transfer shall be based on load. At this point the stop valves are ramped open. the control valves are fully open. All rights reserved.ANSI/ISA–77. To prevent early opening of the stop valves. the first-stage pressure control should be placed in service before the transfer. During a transfer. 4.16. and only transfers after generator breaker closure shall be permitted. An operator shall be notified when an automatic transfer is initiated. and the stop valves are fully open.2.17. and the intercept valves are fully open. These values shall be restricted access parameters. The operator shall have the ability to select single or sequential. the control valves are ramped closed until the turbine control system determines the control valves are restricting steam flow. These permissives should be based on load and valve position. The single-to-sequential transfer will ramp the valves to their desired position at a ramp rate. . 4. Intercept valves can be tested independent of the reheat stop valves. independent overspeed trip system. the first-stage pressure control should be placed in service before the valve test. Permissives shall be included that prevent unwanted operation of the turbine during a test. The following trips shall be generated within the turbine control system unless incorporated within a separate turbine trip system: a) Excessive thrust position b) Low-control oil pressure c) Low-lube oil pressure Copyright 2010 ISA. the trips generated within the turbine control system shall include a) loss of two of the three speed-sensing devices.14.– 21 – ANSI/ISA–77. d) turbine overspeed. Valve testing shall not be permitted during steam admission transfers or while a speed/load ramp operation is in progress. Any of these shall directly trip the unit. Turbine trips Depending upon the turbine manufacturer. the turbine load shall not vary by more than ±3% of rated load. Stop-valve testing will vary depending upon turbine and valve design. permissives shall be included to ensure the turbine control system can compensate for the loss of steam flow during the test. e) Operator initiated trip. there are several components that can initiate a trip of the turbine. Interlocks shall prevent operation of the reheat stop valve when the intercept valve is open. stopvalve testing shall only be allowed when the generator breaker is closed. closing all of the turbine admission valves as quickly as possible.01-2010 closed. During a test. These can include the turbine control system. These permissives should be based on load and valve position. Operator displays shall identify that a turbine valve test is in progress. Additionally. 4. Reheat stop valves shall be tested with its associated intercept valve(s). All rights reserved.4. All of the steam admission valves shall stay closed until the operator takes action to reset the turbine.18. and f) turbine trip status (when a system external to the turbine control system trips the unit. If full-stroke testing is required. As minimum criteria. When the turbine is not in operation. the turbine control system shall use indication of the turbine trip status to also initiate a trip condition). . The turbine’s target speed/load shall be maintained throughout the test. To minimize the upset during a valve test. each valve shall have the capability of being stroked for maintenance purposes individually (test of ability to move the valve over the design test range). The control system shall permit only one test sequence at a time. c) loss of overspeed protection system. and a separate turbine trip system. b) loss of control power. 3.ANSI/ISA–77. These requirements are specified in Section 4.2. 4.5.14.01-2010 – 22 – d) Loss of vacuum e) Turbine supervisory instrumentation f) Plant-trip schemes An indication of the first event (within the turbine control system) that initiated the turbine trip shall be provided to the operator. All rights reserved. The following table summarizes the control functions and respective selections. Operator control functions The operator control interface shall provide the ability to select the required modes of operation. target values. Operator information The following information shall be available to the control room operator: a) Turbine speed b) Generator load c) Remote load demand d) Load-limit setpoint e) Inlet steam pressure f) First-stage (impulse) steam pressure g) Turbine trip status h) Generator breaker position i) j) Turbine runback status Initial-pressure regulator status k) Position indication for all valves l) Valve test status m) Steam admission and valve transfer status n) Controller outputs o) Active control mode 4. . Copyright 2010 ISA.1.5. and rates of change.5. Operator interface 4. and e) initiation of a runback (refer to 4. The following alarms shall be generated if the turbine control system is initiating the trip: a) High-thrust position b) Low-control oil pressure c) Low-lube oil pressure d) High condenser pressure Copyright 2010 ISA.– 23 – ANSI/ISA–77.4.3. d) initial pressure regulator becomes active.14. feedback failure. All rights reserved.5. Alarm requirements Minimum alarm requirements shall include a) valve position alarms: position error. deviation alarm.4.01-2010 Table 4. or is disabled for any reason (refer to 4. b) speed monitoring: loss of speed sensor(s).14). . is selected out of service. c) speed droop becomes active (refer to 4.15).9).4. servo coil fault.1 – Operator functions and control modes Function Speed Control Mode selection Only control available when generator breaker open Default when generator breaker closed and no other control in service Always in service In / Out service In / Out service In / Out service Rate of Change selection Yes Adjustable setpoint Yes Open Loop Load Control Yes Yes Load Limiter Remote Load Control Megawatt Control First Stage Pressure Control Inlet Pressure Control Initial Pressure Regulator Steam Admission Control N/A N/A Yes N/A Yes N/A Yes N/A In / Out service In / Out service Transfer mode and Start / Halt Start / Cancel / Halt Start / Stop N/A N/A N/A Yes Optional N/A Valve Test Overspeed Protection Test N/A N/A N/A N/A 4. Training shall include how to modify restricted access parameters.01-2010 – 24 – e) Turbine supervisory 5. All rights reserved.3.ANSI/ISA–77. 5.2. Technicians Technicians shall be trained to be capable of diagnosing and repairing any problem encountered during operation (with only telephone support from the control system vendor for unique and extremely difficult problems). . Engineers Engineers shall be trained to be capable of reading and understanding the turbine control logic. Copyright 2010 ISA. Training 5. Engineers also shall have the capability of making changes to the logic as necessary. Operators Operators shall be trained to be capable of performing control and test functions.1. Operators also shall be able to interpret and understand corrective actions for system alarms and trips. 5.14. 000 kW” IEEE 122 “Recommended Practice for Functional and Performance Characteristics of Control Systems for Steam Turbine-Generator Units” ASME PTC 6 “Steam Turbines” Copyright 2010 ISA. .01-2010 Annex A 1) Standards Referenced in this Document: API STD 670 “Machinery Protection Systems” API Publications Global Engineering Documents 15 Inverness Way East M/S C303B Englewood.ihs. and Canada) 303-397-7956 (Local and International) 2) Other Related Standards: API STD 611 Services” NEMA SM23 NEMA SM24 “General-purpose Steam Turbines for Petroleum.– 25 – ANSI/ISA–77.com 1-800-854-7179 (Toll-free in the U.S. Chemical and Gas Industry “Steam Turbines for Mechanical Drive Service” “Land Based Steam Generator Sets 0 to 33. All rights reserved.global.14. CO 80112-5776 USA www. O. NC 27709 ISBN: 978-1-936007-67-7 .Developing and promulgating sound consensus standards. recommended practices. and reviewers. please write: ISA Attn: Standards Department 67 Alexander Drive P. and technical reports is one of ISA’s primary goals. To obtain additional information on the Society’s standards program. chairmen. ISA administers United States Technical Advisory Groups (USTAGs) and provides secretariat support for International Electrotechnical Commission (IEC) and International Organization for Standardization (ISO) committees that develop process measurement and control standards. To achieve this goal. the Standards and Practices Department relies on the technical expertise and efforts of volunteer committee members. Box 12277 Research Triangle Park. ISA is an American National Standards Institute (ANSI) accredited organization.