ANSI ISA 77 14 01 2010

STANDARD ANSI/ISA–77.14.01 A NSI/ISA–77.14.01-2010 -2010 Fossil Fuel Power Power Plant Steam Steam Turb Turb ine Control s Ap pr ov ed 10 Novem No vem ber 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 S tates 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. reserved.

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ANSI/ISA–77.14.01-2010

Preface This preface, as well as all footnotes and annexes, is included for information purposes and is not part of ANSI/ISA–77.14.01-2010. The standards referenced within this document may contain provisions, which, through reference in this text, constitute requirements of this document. At the time of publication, the editions indicated were valid. All standards are subject to revision, and parties to agreements based on this document are encouraged to investigate the possibility of appl ying the most recent editions of the standards indicated within this document. Members of IEC and ISO maintain registers of currently valid International Standards. ANSI maintains registers of currently valid U.S. National Standards. This document has been prepared as part of the service of ISA, The International Society of Automation, toward a goal of uniformity in the field of instrumentation. To be of real value, this document should not be static but should be subject to pe riodic review. Toward this end, the Society welcomes all comments and criticisms and asks that they be addressed to the Secretary, Standards and Practices Board; ISA; 67 Alexander Drive; P. O. Box 12277; Research Triangle Park, NC, 27709; Telephone (919) 549-8411; Fax (919) 549-8288; E-mail: [email protected]. The ISA Standards and Practices Department is aware of the growing need for attention to the metric system of units in general, and the International System of Units (SI) in particular, in the preparation of instrumentation standards. The Department is further aware of the benefits to USA users of ISA standards of incorporating suitable references to the SI (and the metric system) in their business and professional dealings with other countries. Toward this end, this Department will endeavor to introduce SI-acceptable metric units in all new and revised standards, recommended practices, and technical reports to the greatest extent possible. Standard for Use of the International System of Units (SI): The Modern Metric System, published by the American Society for Testing & Materials as IEEE/ASTM SI 10-97, and future revisions, will be the reference guide for definitions, symbols, abbreviations, and conversion factors. It is the policy of ISA to encourage and welcome the participation of all concerned individuals and interests in the development of ISA standards, recommended practices, and technical reports. Participation in the ISA standards-making process by an individual in no way constitutes endorsement by the employer of that individual, of ISA, or of any of the standards, recommended practices, and technical reports that ISA develops. CAUTION — ISA DOES NOT TAKE ANY POSITION WITH RESPECT TO THE EXISTENCE OR VAL IDITY OF ANY PATENT RIGHTS ASSERTED IN CONNECTION WITH THIS DOCUMENT, AND ISA DISCLA IMS LIABIL ITY FOR THE INFRINGEMENT OF ANY PATENT RESULTING FROM THE USE OF THIS DOCUMENT. USERS ARE A DVISED THAT DETERMINATION OF THE VALIDITY OF ANY PATENT RIGHTS, AND THE RISK OF INFRINGEMENT OF SUCH RIGHTS, IS ENTIRELY THEIR OWN RESPONSIBILITY. PURSUANT TO ISA’S PATENT POLICY, 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, NON-DISCRIMINATORY BASIS, WITH A FAIR AND REASONABLE ROYALTY RATE AND FAIR AND REASONABLE TERMS AND CONDITIONS. FOR MORE INFORMATION ON SUCH DISCLOSURES AND LETTERS OF A SSURANCE, CONTACT ISA OR VISIT www.isa.org/StandardsPatents. OTHER PATENTS OR PATENT CLAIMS MAY EXIST FOR WHICH A DISCLOSURE OR LETTER OF ASSURANCE HAS NOT BEEN RECEIVED. ISA IS NOT RESPONSIBL E FOR IDENTIFYING PATENTS OR PATENT APPLICATIONS FOR WHICH A LICENSE MAY B E REQUIRED, FOR CONDUCTING

Copyright 2010 ISA. All rights reserved.

ANSI/ISA–77.14.01-2010

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INQUIRIES INTO THE LEGAL VALIDITY OR SCOPE OF PATENTS, OR DETERMINING WHETHER ANY LICENSING TERMS OR CONDITIONS PROVIDED IN CONNECTION WITH SUBMISSION OF A LETTER OF ASSURANCE, IF ANY, OR IN ANY LICENSING AGREEMENTS ARE REASONABLE OR NON-DISCRIMINATORY. ISA REQUESTS THAT ANYONE REVIEWING THIS DOCUMENT WHO IS AWARE OF ANY PA TENTS THAT MAY IMPA CT IMPLEMENTATION OF THE DOCUMENT NOTIFY THE ISA STANDARDS AND PRACTICES DEPARTMENT OF THE PATENT AND ITS OWNER. ADDITIONALLY, THE USE OF THIS DOCUMENT MAY INVOLVE HAZA RDOUS MATERIALS, OR EQUIPMENT. THE DOCUMENT CANNOT ANTICIPATE ALL POSSIBLE APPLICATIONS OR ADDRESS ALL POSSIBLE SAFETY ISSUES ASSOCIATED WITH USE IN HAZARDOUS CONDITIONS. THE USER OF THIS DOCUMENT MUST EXERCISE SOUND PROFESSIONAL JUDGMENT CONCERNING ITS USE AND APPLICABILITY UNDER THE USER’S PARTICULAR CIRCUMSTANCES. THE USER MUST ALSO CONSIDER THE APPLICAB ILITY OF ANY GOVERNMENTAL REGULATORY LIMITATIONS AND ESTABLISHED SAFETY AND HEALTH PRACTICES BEFORE IMPLEMENTING THIS STANDARD. The following people served as vo ting members of Subcommittee ISA77.14: NAME

COMPANY

Jeffrey Schleis, 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

Wood Group TCS CH2M Hill Compania Inspeccion Mexicana Consultant Turbomachinery Controls Solutions LLC Applied Control Systems Fluor Canada Ltd. Power Consultants ABB Inc. Consultant Consultant Tennessee Valley Authority Luminant Power First Energy Generation Corp. Invensys Process Systems Taft Engineering Inc. Sargent & Lundy LLC

The following p eople served as vo ting m embers of ISA77: NAME

COMPANY

G. McFarland, Managing Director L. Altcheh J. Batug D. Christopher G. Cohee D. Crow R. Eng A. Gavrilos J. Gilman W. Hocking W. Holland

Emerson Process Management Israel Electric Corp. PPL Generation LLC Consultant Applied Control Systems Invensys Foxboro* Hitachi Power Systems America ABB Inc.* JFG Technology Transfer LLC Invensys Process Systems* CH2M Hill


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R. Hubby H. Johansen R. Johnson D. Lee G. Mookerjee J. Olson P. Reeves D. Roney M. Skoncey T. Stevenson C. Taft A. Zadiraka

ANSI/ISA–77.14.01-2010

Robert N. Hubby Consulting Bechtel Power Corp. IC Engineering ABB Inc.* Detroit Edison Co. Tennessee Valley Authority Luminant Power URS-Washington Division First Energy Generation Corp. Constellation Energy Taft Engineering Inc. Consultant

This standard was approved for p ublication by the ISA Standards and Practices Board on 10 November 2010. NAME P Brett M. Coppler E. Cosman B. Dumortier D. Dunn R. Dunn J. Gilsinn E. Icayan J. Jamison D. Kaufman K. Lindner V. Maggioli T. McAvinew A. McCauley R. Reimer N. Sands H. Sasajima T. Schnaare J. Tatera I. Verhappen R. Webb W. Weidman J. Weiss M. Widmeyer M. Wilkins M. Zielinski

COMPANY Honeywell Inc. Ametek, Inc. The Dow Chemical Co. Schneider Electric Aramco Services Co. DuPont Engineering NIST/MEL ACES Inc. EnCana Corporation Ltd. Honeywell International, Inc. Endress+Hauser Process Solutions AG Feltronics Corp. Jacobs Engineering Chagrin Valley Controls, Inc. Rockwell Automation DuPont Yamatake Corp. Rosemount, Inc. Tatera & Associates, Inc. Industrial Automation Networks, Inc. ICS Secure LLC Consultant Applied Control Solutions LLC Kahler Engineering, Inc. Yokogawa IA Global Marketing Emerson Process Management


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ANSI/ISA–77.14.01-2010

CONTENTS 1.

Scope

9

2.

Purpose

9

3.

Definitions

9

4.

Design requirements

12

4.1.

Instrumentation

12

4.2.

Overspeed trip system

13

4.3.

Turbine control system design

13

4.4.

Turbine control system functio ns

14

4.5.

Operator interf ace

22

5.

Training

24


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1.

ANSI/ISA–77.14.01-2010

Scope

This standard addresses steam turbine governor controls and overspeed protection of steam turbine generators in fossil power plants. Specifically excluded from consideration are single valve and controlled extraction turbines, mechanical drive turbines, automated startup/shutdown systems, turbine supervisory instrumentation, steam bypass systems, and turbine water induction prevention (TWIP) systems.

2.

Purpose

The purpose of this standard is to establish the minimum requirements for functional design speci fications of steam turbine control systems for use in fossil fueled power generation plants.

3.

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: 3.1.

Bumpless transfer:

Automatic tracking such that any control mode transfer is accomplished without a sudden process upset. 3.2.

Controller:

Any manual or automatic device or system of devices used to regulate processes within defined parameters. 3.3.

Contro l 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. 3.4.

Distri but ed con tro l syst em (DCS):

A digital control system in which the control computations are performed on multiple processing units. Decision-making equipment with its associated power supplies, control processor(s), I/O hardware, and sensing devices. 3.5.

Emergency condit ion:

Any condition that requires operator or control system intervention to prevent personal injury or equipment damage. 3.6.

Failsafe:

The capability to go to a predetermined safe state in the event of a specific malfunction. 3.7.

Fault tol erant:

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. 3.8.

First-st age press ure:

The pressure within a steam turbine at the point where the steam exits the first row of turbine blades. The pressure at this point is closely proportional to the flow rate of steam through the turbine. First-stage pressure is also referred to as impulse pressure by some turbine manufacturers. 3.9.

Full arc:

Steam admission that throttles steam equally through all nozzle segments or partitions simultaneously. See partial arc.


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3.10.

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Governor valve:

See control valve. 3.11.

Impuls e pressu re:

See first-stage pressure. 3.12.

Inlet pressu re:

Pressure immediately upstream of the throttle valve(s). Inlet pressure is also referred to as main steam pressure or throttle pressure by some turbine manufacturers. 3.13.

Intercept valve:

A valve or set of valves in position to regulate steam flow from the reheater to the IP turbine. The intercept valves are an integral part of the overspeed protection system and, depending on the turbine manufacturer, may be of the modulating or open/closed d esign. In some applications, the intercept valves are used to regulate steam flow during startup. 3.14.

Initial press ure regulato r (IPR):

A device or function that modulates the control valves closed on loss of inlet pressure. 3.15.

Load con tro l:

Control of generator output power while the generator breaker is closed. 3.16.

Load limi ter:

A device or function that limits turbine flow and therefore limits the power generated by the turbine. 3.17.

Lin ear variable diff erential transf ormer (LVDT):

A form of position measurement made by varying the inductive coupling (core rod position) between the primary and secondary windings of a transformer. 3.18.

Main steam press ure:

See inlet pressure. 3.19.

Overspeed:

Any speed above rated synchronous speed. 3.20.

Operator parameter:

A parameter within the turbine control system accessible from an operator console by anyone with operator access rights. 3.21.

Partial arc:

Steam admission that does not throttle steam equally through all nozzle segments or partitions. See full arc . 3.22.

Reset:

An action taken to prepare the turbine for startup. This is also sometimes referred to as latching the turbine. 3.23.

Restrict ed 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.


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3.24.

ANSI/ISA–77.14.01-2010

Runback:

An action initiated by the loss of selected auxiliary equipment, in which the load is reduced automatically to a level which can be sustained with the remaining auxiliary equipment. 3.25.

Rundown:

An action initiated by an undesirable operating condition, in which the load is reduced until the undesirable condition has cleared. 3.26.

Sequential valve mod e:

Control valves opening in a sequence; one or more valve(s) opening following another. See partial arc. 3.27.

Shall and should:

The word “SHALL” is to be understood as a REQUIREMENT; the word “SHOULD” as a STRONG RECOMMENDATION. 3.28.

Single-valve mod e:

Control valves opening simultaneously. See full arc. 3.29.

Speed con trol :

Closed-loop control of turbine speed (RPM) before synchronization. 3.30.

Speed droop:

The ratio of the percentage speed change to the resulting percentage valve-position change. Speed droop is inversely proportional to the steady-state gain of the speed controller. 3.31.

Stop valve:

A valve or set of valves used to shut off steam flow to the turbine during turbine shutdown. The stop valves are tripped closed by the turbine protection system. In some applications, these valves are used to regulate steam flow during startup. 3.32.

Synchronization:

The process of matching frequency, phase, and vol tage between the turbine generator and the utility grid to allow proper breaker closure. 3.33.

Turbin e con trol syst em (TCS):

Decision-making equipment with its associated power supplies, control processor(s), I/O hardware, and sensing devices that monitor and control the turbine. 3.34.

Thrott le press ure:

See inlet pr essure. 3.35.

Thrott le valve:

See stop valve. 3.36.

Trip:

An action where all of the steam turbine valves are closed as quickly as possible. This can occur as a result of an emergency condition or as part of a normal shutdown. 3.37.

Valve pos itio n limi ter:

See load limiter .


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3.38.

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Valve positio n 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. However, some turbine valve actuators may require a closed loop positioning system.

4.

Design requirements

4.1.

Instrumentation

Process-sensing devices (see Figure 4.Error! No text of specified style in document.1 - 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. Separate isolation valves and impulse lines should be run to each pressure-sensing device used for control. Figure 4.Error! No text of specified style in document.1 - Turbine instru mentation (typical) ZT 101

PT 101

ZT 102

H

H

Stop Valve

Control Valve JT 101

PT 102 ST 101

ST 102

ST 103

HP

IP

LP

Generator Intercept Valve

Reheat Stop Valve

ZT 104

Condenser ZT 103

Re-heater

4.1.1.

Speed sensi ng

A minimum of three speed-sensing devices (probes) shall be used for speed control (ST-101, 102, 103). At least one of these speed probes shall be capable of reading turning-gear speed. An additional installed spare-speed probe should be supplied. When the backup overspeed trip system is an electronic design (refer to section 4.2), the speed probes used by the turbine control system shall be independent of those used by a backup electronic overspeed trip system. 4.1.2.

Valve pos itio n

Feedback shall be instrumented for all valves controlled by the turbine control system: stop (ZT101), control (ZT102), reheat stop (ZT103), and intercept valves (ZT104). LVDTs or similar measurement devices shall be used for modulating valves. Limit switches are acceptable for valves whose position is not modulated.


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4.1.3.

ANSI/ISA–77.14.01-2010

Steam press ures

Inlet-pressure transmitter (PT-101). First-stage pressure transmitter (PT-102). 4.1.4.

Generator

Megawatt transducer (JT-101). Generator breaker status 4.1.5.

Turbin e trip status

Typically a pressure signal on the trip oil header. 4.2.

Overspeed trip syst em

Two independent turbine overspeed trip systems shall be provided: The primary system shall be within the turbine control system; 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, API 670. The backup overspeed trip system shall b e capable of tripping the turbine without the involvement of the turbine control system. Speed sensing devices (probes) used by the turbine control system shall be independent of those used by a backup electronic overspeed trip system. The turbine control system and the el ectronic overspeed trip system, when utilized as the backup system for the overspeed trip function, shall perform the trip function through independent solenoids. A multi-toothed surface for speed sensing shall be provided integral with or securely attached to the turbine shaft. Sharing this surface between the turbine control system, a backup electronic overspeed trip system, and a tachometer shall be permitted. Details of the speed sensing measurement shall follow API 670. 4.3.

Turbine control system design

4.3.1.

Architecture

The turbine control system design should be fault tolerant. The failure behavior of components shall be considered and incorporated in the design. The turbine control system shall be designed to be failsafe. The turbine control system functions shall reside in a dedicated controller that is segregated from other plant functions. 4.3.1.1. Diagnostics The control system design shall i nclude diagnostics to monitor and alarm any component failures, including: processor, data transfer, input or output hardware, and power supplies. Diagnostics shall be included to monitor and alarm any analog input (4-20mA, T/Cs, RTDs, etc.) signal failure.


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4.3.2.

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Data arch ival

Archival of turbine control system data is used for performance analysis and not intended for sequence of event analysis. The data update period for data archival shall not exceed 1 sec. The minimum data to be archived include: a)

turbine speed;

b)

generator load;

c)

first-stage steam pressure;

d)

inlet steam pressure;

e)

valve positions;

f)

controller outputs;

g)

active control mode; and

h)

trip-system status.

4.3.3.

Security

Changes to the turbine control system’s logic shall be protected from unauthorized access. Tunable values and parameters shall have restricted access. 4.4.

Turbine control system functi ons

4.4.1.

Turbin e reset

Once all of the trip conditions have been cleared, the operator shall be able to initiate a reset of the turbine. Reset of the turbine is a prerequisite to complete the reset sequence before attempting speed control. Upon confirmation the turbine is reset (turbine trip status i nput cleared), all steam admission valves that are not used to control speed for the selected steam admission mode shall ramp open. Refer to Section 4.4.16 for a definition of possible steam admission modes based on OEM design. The turbine control system shall include interlocks to ensure valves open in a sequence in accordance with the OEM design. 4.4.2.

Normal range speed con trol

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. The speed control system shall use a median-signal select of the three speed sensors. Speed-sensor voting shall switch from median-signal to high-signal select if a speed-sensor fault condition exists. The turbine control system shall automatically transfer to speed control mode when the turbine is initially reset and when the other speed control pe rmissives are satisfied. When this occurs, the speed control setpoint shall be automatically set to no greater than the current turbine speed.


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ANSI/ISA–77.14.01-2010

After the turbine is reset, the turbine control system shall control turbine speed to maintain an operator adjustable setpoint in RPM. The speed controller shall provide at a minimum the equivalent of proportional plus integral control action. This type of control ensures zero speed error under steady-state conditions. The operator shall have the capability of ramping the speed control setpoint at a minimum of three selectable rates expressed in RPM/min. Implementing the ramp as an operator function within predefined limits shall be permitted. The turbine control system shall accommodate an external speed setpoint function (e.g. from an automated turbine startup system). 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. A method shall be implemented to prevent turbine speed from operating continuously in a critical vibration window. The turbine control system shall assume speed control of the turbine when the generator breaker opens, and the speed setpoint at that time shall be the rated speed of the turbine. The speed controller shall provide stable control at all times and regulate within plus or minus one RPM of setpoint during steady speed conditions. On turbines where a steam admission valve transfer occurs before rated speed is reached, 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. 4.4.3.

Overspeed func tio ns

The overspeed functions included in the turbine control system shall use the same speed sensors as the normal range speed control. 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. A failed speed sensor circuit shall be voted as an overspeed condition for that sensor. The overspeed trip setpoint shall be a restricted access parameter. A means of testing and verification of all overspeed trip systems shall be provided. The turbine control system shall have provisions, if necessary, to test the backup overspeed trip system. Activation of onli ne testing functions shall have safeguards to prevent inadvertent operation. Based on the unit size and turbine OEM, there may be several additional overspeed protection functions (e.g. pre-emergency governor, load-drop anticipator, power-load unbalance) that require additional measurements (e.g. reheat pressure and generator current). This functionality shall be i ncorporated into the control system design. 4.4.4.

Synchronization

The turbine control system shall be capable of receiving demand signals for speed setpoint changes during synchronization. This demand input shall be separate from the operator speed control inputs in order to allow different gains, limits, and permissives. 4.4.5.

Initial megawatt pick -up

Upon generator breaker closure, the turbine control shall initiate a step change in flow demand to establish load on the generator. This action shall be a step function and is not subject to the loading rate. After load is established, this function shall have no further action. Initial megawatt pick-up settings shall be restricted access parameters. These parameters shall be implemented as a function of inlet steam pressure.


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4.4.6.

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Isochronou s control mode

Isochronous control is an optional function bu t subject to the following when provided: •

•

4.4.7.

Isochronous control shall be used when the generator breaker is closed, 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. In this situation, the operator shall not be able to select any load-control mode. When the unit is tied to the grid, isochronous control is not allowed, and speed droop shall be utilized as described in Section 4.4.9. Open-loop load con tro l

The transition from speed control to open-loop load control shall be automatic at the time the generator breaker closes. This is the prevailing control mode while the generator breaker is closed unless a closedloop control mode is in service. 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 operator adjustable setpoint shall equate to turbine flow demand. 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. Implementing loading rate as an operator function within predefined limits shall be permitted. The upper limit shall be calculated based on the turbine OEM loading design limits. 4.4.8.

Load limiter functio n

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. The load limiter shall take priority over all control modes. 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. This function operates in addition to and not instead of the l oad limiter function, which is an electronic descendant of the load limiter function traditionally provided with a mechanical governor system. 4.4.9.

Speed dro op

Speed droop shall be enabled when the turbine/generator unit is connected to an electrical grid in parallel with other turbine/generator units. The purpose of speed droop is to enhance grid stability and allow the turbine control system to respond to changes i n bus frequency without operator intervention. Speed droop shall be proportional-only control. The proportional control setting, called regulation, i s defined such that 5% regulation will mean that a 5% error in turbine speed will cause 100% travel of the turbine valves. The regulation value shall be adjustable from 2% to 10%. The specific setting shall be in accordance with the authority having jurisdiction. There shall be an allowable speed error deadband. The deadband shall be a restricted access parameter adjustable between 0 and +/- 10 RPM. T he specific setting shall be in accordance with the authority having jurisdiction.


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ANSI/ISA–77.14.01-2010

Figure 4.2 – 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. Speed droop settings shall be restricted access parameters. An alarm shall be initiated any time speed droop exceeds the deadband and is active. This alarm, along with the current load demand, shall be provided to the unit load master to coordinate steam generation. 4.4.10. Remote load cont rol The turbine control system shall provide at least one remote load control mode that enables a turbine load reference (i.e. open-loop load demand, MW setpoint, or load limiter) to be controlled by an external system. This would typically be used to interface with an automatic load d ispatch system, unit load master, or other control system. The remote load control mode shall have the capability to interface with the available signal type from the load control system. 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. When the remote signal is implemented via discrete raise/lower inputs, typical with automatic dispatch, the turbine control system shall be capable of pulse width, pulse frequency, and pulse counting modulation. 4.4.11. Closed-loo p megawatt con trol 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. The turbine control system shall provide an operator adjustable setpoint in megawatts and a controller to maintain that setpoint. The cl osed-loop megawatt controller shall be at a minimum the equivalent of proportional-plus-integral control action. This type of control ensures zero load error under steady-state conditions. Copyright 2010 ISA. All rights reserved.

ANSI/ISA–77.14.01-2010

•

•

•

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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 loading rate is implemented as an operator adjustable function, there shall be predefined limits. The upper l imit shall be calculated based on the turbine loading design limits. Placing the closed-loop megawatt control in and out of service shall be a bumpless transfer. Failure of the megawatt control signal shall prevent this control from being put in service by the operator. If the failure occurs while this control is active, the control system shall automatically take this function out of service. See Section 4.5.2 for controller modes.

4.4.12. Closed-loo p, firs t-stage (impul se) pressu re cont rol Closed-loop, 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. Closed-loop, first-stage pressure control shall provide a controller to maintain first-stage pressure to the setpoint value. It shall have at a minimum the equivalent of proportional-plus-integral control action. This type of control ensures zero pressure error under steady-state conditions. Placing the closed-loop, first-stage pressure control in and out of service shall be a bumpless transfer. Failure of the impulse pressure control signal shall prevent this control from being put in service by the operator. If the failure occurs while this control is active, the control system shall automatically take this function out of service. See Section 4.5.2 for controller modes.

4.4.13. Close-loop inlet press ure con trol 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. An operator adjustable setpoint shall be provided in inlet steam pressure units and shall provide a controller to maintain setpoint. The inlet pressure control shall have at a minimum the equivalent of proportional-plus-integral control action. This type of control ensures zero pressure error under steadystate conditions. Placing the closed-loop inlet pressure control in and out of service will be a bumpless transfer. Failure of the inlet pressure signal shall prevent this control from being put in service by the operator. If the failure occurs while this control is active, the control system shall automatically take this function out of service. See Section 4.5.2 for controller modes. 4.4.14. Initial press ure regulato r (IPR) Initial pressure regulator shall be i mplemented to accommodate either of two methodologies. 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. 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.


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ANSI/ISA–77.14.01-2010

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. The initial pressure regulator shall be initiated when inlet pressure drops below setpoint or when inlet pressure decreases at a high rate. The setpoint shall be either fixed or adjustable by the operator. The operator shall also have the ability to place this control loop in or out of service. 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. Th e deadband amount shall be a restricted access parameter. The initial pressure regulator shall include a method of preventing the unit from ramping to a zero load setpoint. An alarm shall be generated if initial pressure regulator becomes active, is selected out of service, or is disabled for any reason. Failure of the inlet pressure control signal shall prevent this control from being put in service by the operator. If the failure occurs while this control is active, the control system shall automatically take this function out of service. See Section 4.5.2 for controller modes. 4.4.15. Runback s and run down s A minimum of one turbine runback and one turbine rundown shall be provided. When the turbine control system interfaces to an automatic load dispatch system, unit load master or other control system that has implemented turbine runbacks and rundowns as part of the remote demand signal, 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. 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. When initiated, a runback overrides the current mode of operation and lowers the unit demand. E ach runback provided shall have i ts own dedicated lower threshold and rate. Once initiated, the runback will continue until the threshold is reached. If more than one runback is initiated at a time, the fastest rate shall prevail. When initiated, a rundown overrides the current mode of operation and lowers the unit demand. Each rundown provided shall have its own dedicated lower threshold and rate. Once initiated, the rundown will continue until the threshold is reached or the initiating condition is cleared. If more than one rundown is initiated at a time, the fastest rate shall prevail. An alarm shall be generated when a runback or rundown is initiated. Each runback and rundown will generate its own alarm. 4.4.16. Steam admiss ion contr ol Steam admission control defines the sequence of operation for each type of turbine valve. The following section describes the common sequences for various OEM desi gns. 4.4.16.1. Stop valve to con trol valve Depending upon turbine design, the transfer from stop to control valves can be prior to or after synchronization. Depending upon turbine control valve configuration, this transfer will result in either fullarc or partial-arc operation. The permissives to enable the transfer shall match the OEM requirements, and the transfer shall be operator-initiated and/or automatically i nitiated.


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Before a transfer occurs, the control valves are full y open, and the stop valves are modulating to maintain speed or load. During a transfer, the control val ves are ramped closed until the turbine control system determines the control valves are restricting steam flow. At this point the stop valves are ramped open. The transfer is complete when the control val ves are modulating to maintain speed or load, and the stop valves are fully open. To prevent early opening of the stop valves, a control valve position permissive shall be included to prevent the transfer occurring with the control valves open above this value. This value shall be a restricted access parameter. The transfer ramp times shall be adjustable to minimize the upset caused d uring the transfer. These values shall be restricted access parameters. When the transfer is initiated automatically, the transfer shall be based on speed, load, or valve position. An operator shall be notified when an automatic transfer is initiated. 4.4.16.2. Single to sequent ial Single-to-sequential valve transfer applies to turbines designed to have individual actuation of the control valves. This allows operation of the control valves together with one demand signal (single) or staggered in operation (sequential). The transfer shall b e operator-initiated and/or automatically initiated while the generator breaker is closed. When this function is possible, the unit shall start in the single mode, and only transfers after generator breaker closure shall be permitted. The operator shall have the ability to select single or sequential, or to halt the transfer. Any transfer shall be reversible. The single-to-sequential transfer will ramp the valves to their desired position at a ramp rate. To minimize the upset during the transfer, the first-stage pressure control should be placed in service before the transfer. The ramp rate shall be a restricted access parameter. During the transfer, all other load control functions shall be active, such as runbacks and load changes. When the transfer is initiated automatically, the transfer shall be based on load. An operator shall be notified when an automatic transfer is initiated. 4.4.16.3. 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. The permissives to enable the transfer shall match the OEM requirements and shall be initiated by the operator. Before a transfer occurs, the stop valves are closed, and the intercept valves are modulating to maintain speed or load. During a transfer, the stop valves are ramped open until the control system determines the stop valves are governing steam flow. At this point the intercept valves are ramped open. The transfer ramp rates shall be restricted access parameters. The transfer is complete when the stop valves are modulating to maintain speed or load, and the intercept valves are fully open. 4.4.17. Valve testin g Steam-valve test functions shall be a part of the turbine control system. This i ncludes both modulating and non-modulating valves. The turbine design will dictate which test functions are possible. Testing shall be initiated by operator action. The operator shall be able to halt the test momentarily or cancel a test at any time. When testing control valves, permissives shall be included to ensure the turbine control system can compensate for the loss of steam flow during the test. These permissives should be based on load and valve position. Additionally, control-valve testing shall only be allowed when the generator breaker is Copyright 2010 ISA. All rights reserved.

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ANSI/ISA–77.14.01-2010

closed. To minimize the upset during a valve test, the first-stage pressure control should b e placed in service before the valve test. Stop-valve testing will vary depending upon turbine and valve design. If full-stroke testing is required, permissives shall be included to ensure the turbine control system can compensate for the loss of steam flow during the test. These permissives should be based on load and valve position. Additionally, stopvalve testing shall only be allowed when the generator breaker is closed. Reheat stop valves shall be tested with its associated intercept valve(s). Interlocks shall prevent operation of the reheat stop valve when the intercept valve is open. Intercept valves can be tested independent of the reheat stop valves. Valve testing shall not be permitted during steam admission transfers or while a speed/load ramp operation is in progress. Operator displays shall identify that a turbine valve test i s in progress. The control system shall permit only one test sequence at a time. The turbine’s target speed/load shall be maintained throughout the test. During a test, the turbine load shall not vary by more than ±3% of rated load. When the turbine is not in operation, each valve shall have the capability of being stroked for maintenance purposes individually (test of abili ty to move the valve over the design test range). Permissives shall be included that prevent unwanted operation of the turbine during a test. 4.4.18. Turbine trips Depending upon the turbine manufacturer, there are several components that can initiate a trip of the turbine. These can include the turbine control system, independent overspeed trip system, and a separate turbine trip system. Any of these shall directly trip the unit, closing al l of the turbine admission valves as quickly as possible. All of the steam admission valves shall stay closed until the operator takes action to reset the turbine. As minimum criteria, the trips generated within the turbine control system shall include a) loss of two of the three speed-sensing devices; b) loss of control power; c)

loss of overspeed protection system;

d) turbine overspeed; e) Operator initiated trip; and f)

turbine trip status (when a system external to the turbine control system trips the unit, the turbine control system shall use indication of the turbine trip status to also initiate a trip condition).

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


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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. 4.5.

Operator interf ace

4.5.1.

Operator info rmatio n

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)

Turbine runback status

j)

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 4.5.2.

Operator contro l function s

The operator control interface shall provide the ability to select the required modes of operation, target values, and rates of change. These requirements are specified in Section 4.3. The following table summarizes the control functions and respective selections.


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ANSI/ISA–77.14.01-2010

Table 4.1 – Operator func tions and contro l mod es Function

Mode selection

Rate of Change selection

Adjustable setpoint

Speed Control

Only control available when generator breaker open

Yes

Yes

Open Loop Load Control

Default when generator breaker closed and no other control in service

Yes

Yes

Load Limiter

Always in service

N/A

Yes

Remote Load Control

In / Out service

N/A

N/A

Megawatt Control

In / Out service

Yes

Yes

First Stage Pressure Control

In / Out service

N/A

N/A

Inlet Pressure Control

In / Out service

N/A

Yes

Initial Pressure Regulator

In / Out service

N/A

Optional

Steam Admission Control

Transfer mode and Start / Halt

N/A

N/A

Valve Test

Start / Cancel / Halt

N/A

N/A

Overspeed Protection Test

Start / Stop

N/A

N/A

4.5.3.

Alarm requir ements

Minimum alarm requirements shall include a) valve position alarms: position error, feedback failure, servo coil fault; b) speed monitoring: loss of speed sensor(s), deviation alarm; c)

speed droop becomes active (refer to 4.4.9);

d) initial pressure regulator becomes active, is selected out of service, or is disabled for any reason (refer to 4.4.14); and e) initiation of a runback (refer to 4.4.15). 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


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e) Turbine supervisory

5.

Training

5.1.

Operators

Operators shall be trained to be capable of performing control and test functions. Operators also shall be able to interpret and understand corrective actions for system al arms and trips. 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). Training shall include how to modify restricted access parameters. 5.3.

Engineers

Engineers shall be trained to be capable of reading and understanding the turbine control logic. Engineers also shall have the capability of making changes to the logic as necessary.


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ANSI/ISA–77.14.01-2010

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, CO 80112-5776 USA www.global.ihs.com 1-800-854-7179 (Toll-free in the U.S. and Canada) 303-397-7956 (Local and International)

2) Other Related Standards: API STD 611 Services”

“General-purpose Steam Turbines for Petroleum, Chemical and Gas Industry

NEMA SM23

“Steam Turbines for Mechanical Drive Service”

NEMA SM24

“Land Based Steam Generator Sets 0 to 33,000 kW”

IEEE 122 “Recommended Practice for Functional and Performance Characteristics of Control Systems for Steam Turbine-Generator Units” ASME PTC 6

“Steam Turbines”


Developing and promulgating sound consensus standards, recommended practices, and technical reports is one of ISA’s primary goals. To achieve this goal, the Standards and Practices Department relies on the technical expertise and efforts of volunteer committee members, chairmen, and reviewers. ISA is an American National Standards Institute (ANSI) accredited organization. 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 obtain additional information on the Society’s standards program, please write: ISA Attn: Standards Department 67 Alexander Drive P.O. Box 12277 Research Triangle Park, NC 27709 ISBN: 978-1-936007-67-7

ANSI ISA 77 14 01 2010

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