2 Retrofitting Steam Turbines

RETROFITTING STEAM TURBINES WITH MODERN CONTROL PLATFORMS

Ronald Hitzel Global Business Development Manager Instrumentation & Controls Siemens Westinghouse Power Corporation

Fred Block I&C Engineer Siemens Westinghouse Power Corporation

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PowerGEN 2003 – LasVegas, Nevada Dec. 9-11

RETROFITTING STEAM TURBINES WITH MODERN CONTROL PLATFORMS Abstract Steam turbine owners are being confronted with complex operating processes brought on by deregulation. In order to compete in today’s electrical power market place and meet these complex operating conditions, steam turbine owners have begun to retrofit their steam turbine control systems with modern control platforms. Because these modern control platforms provide better control of the steam turbine, the flexibility to meet the demands of the market can be obtained. The control system design is critical to optimize availability and reliability while minimizing impact on maintenance and capital budgets. Issues such as turbine performance, controls integration and future upgrades are sometimes overlooked when implementing a turbine control system modification. This paper presents examples of steam turbine control system design and integration and offers recommendations for a successful steam turbine control upgrade.

© Siemens AG 2003. All rights reserved.

RETROFITTING STEAM TURBINES WITH MODERN CONTROL PLATFORMS

Ronald Hitzel Global Business Development Manager Instrumentation & Controls Siemens Westinghouse Power Corporation 4400 Alafaya Trail, MC 250, Orlando, FL 32826-2399 Telephone: (407) 736-2553; Fax: (407) 736-5025; E-mail: [email protected] Fred Block I&C Engineer Siemens Westinghouse Power Corporation 1345 Ridgeland Drive, Suite 116, Alpharetta, GA 30004 Telephone: (678) 256-1606; Fax: (678) 256-1558; E-mail: [email protected]

Introduction Better performance throughout the steam turbines operational life improves cost efficiency. Today, better control is even more important then before, as older turbines operate beyond their original life expectancy. Since the early 1980’s digital controls have been the accepted standard in many North American and European manufacturing and process industries. Recent developments in digital processing technology (i.e. faster processing speeds, lower cost, and smaller sizes) make digital turbine control the preferred technology of power plant operators. Traditional steam turbine controls were accomplished with a fly-ball governor for speed indication, mechanical linkages, and low-pressure turbine lube oil. Although these systems are fairly reliable, they are becoming costly to maintain, as many of the original control devices are now obsolete. Replacement parts, if available, are becoming expensive with long delivery times. Maintenance of these systems required a certain degree of familiarity and knowledge of the instrumentation of its era. The knowledge base involving implementation of controls on mature steam turbines has diminished over the years, which directly affects unit availability and reliability. Turbine Control Philosophy The modern digital turbine control system (TCS) is designed to control the main steam flow to the steam turbine in all operational conditions by means of the turbine throttle, governor, admission, and or extraction control valves. The control functions are conducted through the use of simplex or redundant electronic functions incorporated within the TCS software and hardware, integrated through the use of servo coil actuators.

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Master controllers automatically engage when required to ensure the appropriate rates of change match the mode of operation of the turbine. Setpoint controls, open and closed-loop control functions, as well as continuous monitoring functions associated with the TCS system prevent the turbine generator from assuming inadmissible operating conditions, thus avoiding the necessary response of the turbine protection equipment and possible damage to the machine. This is the predominant operating philosophy surrounding the high availability criteria of the turbine generator. The vendor should provide each of these functions within their standard turbine control packages. Each of these functions can be inhibited as necessary to facilitate proper integration within the existing Distributed Control System (DCS) as required. The principle features of the TCS system are summarized as follows: •

Speed Control

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Inlet/Admission Pressure Control-two channel selection which facilitates initial pressure (boiler follow mode) and limit pressure (turbine follow mode) functions

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Load Control-via either a load setpoint command from a DCS, or can be configured to receive MW input for utilization of the load control function developed within the system, or can be configured stand-alone as a MW or Speed Droop function.

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Turbine Stress Influence

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Frequency Influence

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ADS (Automatic Dispatch System) Influence

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Valve Lift Control

The TCS system ensures stable operation throughout all operational phases, i.e. during unit start up, shutdown, parallel operation, Island mode, etc. In generation applications, full load rejections created by a sudden separation from the grid (lightning strike in the field, etc.) are controlled through the TCS thereby preventing an over-speed condition and collateral damage from occurring. Within the standard design of the TCS system, individual device inputs within the master controller algorithms developing a 1 of 2, 2 of 3, and or 2 of 4 cross configuration voting functions can be deselected through the use of an optional password protected engineering client/server Operating Terminal (OT) station. In certain critical systems, automatic de-selection is implemented upon a “loss” of the device-input signal, with the system automatically returning to a normal state upon “correction” of the issue. What this means is that the system “senses” each device input signal, monitoring it for quality, in the event the device input falls outside of the pre-selected, configurable threshold (for example, one of the active speed pick-ups just failed high), then the device is removed

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from it’s associated algorithm. An alarm is issued, alerting the operator of the device malfunction, and the control algorithm automatically transfers to the next assigned device redundancy level. Upon correction of the malfunction, the control system will automatically transfer to the next device redundancy level to ensure the maximum availability and protection of the system. The TCS should provide automatic and manual shutdown. In automatic shutdown, the system must lower the load until the generator breaker opens on reverse current. On manual shutdown, the operator will open the generator breaker manually once the turbine is at minimum load. The TCS Software System Comprises the Following Standard Master Controllers: 1. Speed Control The speed control function provides the operational control involving the speed limiting and acceleration functions of the unit over the entire operating speed range. The speed control system is fully integrated with the load rejection and load anticipatory functions as required, as well as the turbine trip system. The speed control function is designed to receive up to three speed inputs. These inputs feed a 1 of 2, 2 of 3, and or 2 of 4 voting algorithm which issue an overspeed trip command. If one of the channels fail, that channel is automatically deselected, an alarm is issued alerting the operator of the malfunction, and the unit shifts to the next available comparison algorithm. In the event the speed channel is repaired (the operator found a loose wire connection in the junction box on the ST), then the unit automatically detects the correction, and shifts back automatically into the pre-configured algorithm. In generation applications, when the generator is on the grid and the turbine controller is in the “load” control mode, the speed control function continues to provide a speed error (influence) input for use in frequency regulation. Comparing the speed reference with the actual speed derives the speed error signal. The frequency detection accuracy is within 10 mHz, with tunable variables controlling deadband and droop characteristics. The desired speed reference is selectable manually from the client Operating Station (OS). The speed acceleration rate (ramp rate) can be selected either manually or automatically through the client OS station. Proportional speed regulation, acceleration/deceleration ramp rates, and turbine/boiler runback functions are entirely configurable through the Engineering Station (ES). Discrete values are provided for selecting steady state operation at lower speed holds, as well as for operation at “rated” speed. Four predominant modes of start-up while under speed control are provided as standard solutions within the TCS system: A speed setpoint is keyed into the system via the client OS, and the operator hits “go”, and the unit ramps at a pre-determined ramp rate (which is programmable via

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password protection) to the desired setpoint and holds at the selected value until another command is issued. The operator manually raises and lowers the speed via a soft-key selector (up or down gradient key). In this function, if the operator selects a “stop” function during a transient condition through the predetermined critical bands, the unit will continue to either increase or decrease to the next available threshold. What this means is that if the operator is telling the unit to ramp up, and then “stops” the command during a critical state, the unit will not stop until after achieving the “high” end of the critical range. The same occurs during a downward gradient change. Depending on the particulars of the steam turbine itself and it’s application use, the unit can be configured to open the governor valve(s), and modulate the stop valve in order to “warm” the unit without breaking turning gear speed. After the unit has gone through it’s initial thermal soak period (which can be configured via either thermal inputs-RTD’s/Thermocouples or via a time-based sequence), the stop valve will continue to open, bringing the unit up to the minimum governor speed (typically 95% rated speed/synchronous speed). This function is completely programmable and generally depends on specific unit requirements. At this point in time, the unit will bring the Governor Valve down below the Stop Valve (in order to shift the control from the stop valve- full arc, to the governor valves-partial arc control), and issues a synch command enable, facilitating generator breaker closure. Another standard function utilized by many customers to facilitate automatic start-up is the configuration of the system according to the unit’s Standard Operating Procedure. Each unit is issued with a Standard Operating Procedure (SOP), which typically is modified in writing and issued by the customer as the operations guide governing the machine. The vendor provides for configuration of the unit to operate based on the time- based sequence issued under the SOP. In other words, the unit would be ramped to a pre-determined setpoint, held at that point on a timer, and then ramped to the next point and so and so forth. At no point would the unit be “allowed” to stop within the critical bandwidths. The TCS employs a configurable, operator controllable, proportional regulation controller to ensure a bumpless transfer from full arc and partial arc admission. A separate function is employed which, when password enabled through the Engineering Station (ES), enables a manually controlled overspeed test. Configurable acceleration rates and gradient ceiling facilitate controlled testing of the mechanical overspeed protection devices. In the event the unit reaches the gradient ceiling prior to the units mechanical devices activating, or the operator disables the function, the unit will automatically coast down to rated speed. Upon achieving synchronous speed, the controller accepts raise and lower impulses from the auto synchronization circuitry. Standard provisions are made within the TCS to facilitate the incorporation of both manual and automatic command and control.

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2. Inlet/Admission Pressure Controller The inlet/admission pressure control provides two channel selection which facilitates initial pressure (boiler follow mode) and limit pressure (turbine follow mode) functions. This automatic control function is activated when the inlet-steam pressure drops to a pre-determined configurable setpoint. This gives the operator the ability to perform sliding pressure control for lower MW minimums. 3. Load Control Once the turbine is on the grid, the TCS can either be transferred automatically or manually into the load control mode of operation. The load control function produces steam flow demand signals via the position controller of the associated servo valve actuators. Logic signals derived from the units load control system (ULCS) indicate operating conditions, such as power load imbalance. The load reference (setpoint) value corresponds to the current desired load as compared to the rated main steam pressure. To initiate a change in desired load, the operator dials in the selected desired setpoint and hits “go”, and the unit ramps at a predetermined ramp rate (which is configurable via password protection) to the desired setpoint and holds at the selected value until another command is issued. The load reference (setpoint) may be changed by either raising or lowering the desired target load at the operator control panel, or from the increase or decrease signals generated by the Generator synchronization functions. Turbine runback control functions reside within the load control logic. This function exists as designed to provide a controlling medium during abnormal conditions whereby an engagement of automatic ramp rates bring the unit down to predetermined values. These predetermined runback ramp rates and setpoint limits are configurable via password protection. Standard turbine runback features designed within the system are: •

Loss of boiler feed water pump

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Loss of condenser vacuum

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Loss of primary coolant/pump (generator H2 coolant circulating water pump)

A load limiter is embedded within the load control function to limit the steady state opening of the control valves thereby limiting the flow of steam to the turbine. The load limit function interfaces to the runback function so that an adjustment of the load limit automatically causes a runback of the load reference setpoint to a level 2% above the predetermined load limit. This desirable function prevents a sudden increase in load when the load limiting function is corrected (for example; the boiler feed water pump circuit breaker was inadvertently turned off, and has been re-energized). The load limit is configurable through the entire range of operation via password protection. The TCS

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is designed to provide an indication of deviation percentage from the load limit and issue an indication when the load limit is activated. A load rejection occurs when the generator breaker opens at load. This situation should be handled by the TCS by rapidly shutting the governor valves thereby minimizing the pending overshoot. This is an anticipatory function triggered by the generator breaker position indication. The governor valves then reopen to achieve preconfigured load rejection speed. A megawatt (MW) feedback loop embedded within the TCS load control function which automatically adjusts the megawatt reference setting to correspond with the actual real load (MW). Through selection of this control loop function through the client OS, the MW error value developed between the relationship of the corrected reference MW and the actual MW is applied to a PI controller, which will automatically adjust the control valve signal to reduce any MW deviation. An initial load pickup (Min-load) function embedded within the TCS load control function provides a configurable (typically 3-5%) step increase that occurs each time the generator is initially synchronized to the grid. This Min-load function is used during initial loading of the machine in order to prevent reverse power conditions upon synch enable and is configurable through password protection at the Engineering Station (ES). An impulse pressure feedback loop is embedded within the TCS load control function to correct the megawatt reference versus the actual megawatt value based on actual Impulse pressure. The impulse pressure error derived from the corrected reference impulse pressure (in MW units) and the actual impulse pressure is applied to the controller, which will trim the control valve signal to reduce any impulse pressure error. 4. Turbine Stress Influence The TCS system is designed to accept influencing from a turbine stress evaluation (TSE) system thereby limiting the acceleration and load ramp gradients. During start-up and shutdown, a TSE would provide an input generated from the algorithm delta created between two thermocouples embedded within the main stop valve (MSV or throttle valve) and main control valve (MCV or governor valve). This value would limit the acceleration and or deceleration limit applied to the turbine via the master controllers. Under normal loading operations, a TSE would provide an input generated from the algorithm delta created between thermocouples embedded within the casing (typically HP and IP, which can be utilized to generate a HP/IP shaft deviation algorithm). This deviation signal is utilized within the master controllers to limit the load gradient applied.

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5. Frequency Influence When the generator is on the grid and the turbine controller is in the “load” control mode, the speed control function continues to provide a speed error (influence) input for use in frequency regulation. Comparing the speed reference with the actual speed derives the speed error signal. The frequency detection accuracy is within 10 mHz, with tunable variables controlling deadband and droop characteristics. 6. ADS (Automatic Dispatch System) Influence The TCS system is designed to accept influencing from an ADS controller, facilitating the remote dispatch loading and unloading of the machine along predetermined ramp gradients. The load limit gradients are configurable through the entire range of operation via password protection. 7. Valve Lift Control The valve lift controller integrates the min-gated valve demand reference versus valve actual (setpoint) functions. Some vendors have standard applications oversampling rates of greater than 20 samples per cyclic event throughout the stroke of the valve to achieve the fastest possible response time. The Turbine Control System (TCS) Processor The brain of the steam turbine controller should be a high-speed digital processor. One example is the S7 Programmable Logic Controller. The S7-416 is a high availability processor with the performance required for applications such as steam turbine control. It acquires measured values and status signals from the I/O, carries out open- and closed-loop control functions, transfers the resulting commands to the I/O and performs all the functions of the group and individual device levels. Clearly structured and vigorously tested control concepts should be available for various configurations of plant control tasks. One example of a specific application would provide a modular-based, fan-free, cost-effective solution with a high degree of expansion and communication options. This user-friendly system provides for the easy implementation of distributed structure that is capable of handling the most sophisticated tasks in the high-end performance range. In your application, this processor will automate the total turbine package. Look for a vendor to configure the TCS to allow push button valve calibration and tuning. This significantly reduces commissioning and startup times. Operating alarms and trends should be easy to see and configure in the TCS operator interface graphics.

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The Turbine Protection System (TPS) Processor A critical part of the steam turbine control system upgrade is the protection system. The protection system must have a robust controller to safely shutdown the turbine in the case of emergency. One such controller is the S7-314C-2DP. This is a high availability processor with the performance required for applications such as steam turbine protection systems. It acquires measured values and status signals from the onboard I/O, carries out open- and closed-loop control functions, transfers the resulting commands to the I/O and performs all the functions of the group and individual device levels. Clearly structured and vigorously tested control concepts are available for various configurations of plant control tasks. This user-friendly system provides for the easy implementation within a distributed architecture that is capable of handling the most sophisticated tasks in the high-end performance range. In the TPS application, these processors will automate the turbine trip system (TPS) package within a triplemodular, 2 out-of-3 voting architecture. Mechanical / Hydraulic Engineering And Modifications The vendor should manage the coordination between the mechanical and hydraulic modifications and the electronic control system requirements, so that the complete control system retrofit is a successful project. Mechanical/Hydraulic Trip Subsystem All new steam turbines are being supplied with electronic trip systems without mechanical bolts for overspeed protection. Many customers have requested upgrades to the existing “Mystery Box” and mechanical bolt style systems. The mechanical upgrade completely replaces the original equipment within a 2-out-of-3, 2-out-of-4 algorithm voting architecture. A prefabricated panel incorporating triple redundant field devices for each of the associated parameters facilitates on-line testing and calibration. Many of the components are designed within the system architecture to facilitate on-line repair and or replacement. In the new electronic control logic, each parameter input is read and compared to a trip limit. If the values (for any parameter) exceed the trip limit, the controls will trip all of the turbine valves. In addition to the normal trip limit comparison, the controls will also compare the values of the like parameters (such as bearing oil pressure), will alarm if the deviation between signal levels exceeds a predetermined threshold limit, or if all signals are trending toward the trip limit. In this way, potential problems can be avoided before a trip condition actually occurs, and on-line maintenance can be performed to correct the problem and avoid a trip. Because the transmitters can be compared, monitored and alarmed, on-line testing of the transmitters is not required. The TPS maintains the inputs for tripping the unit from the auxiliary devices. This input mimics the trip solenoid in the existing trip block assembly.

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A trip-reset input is necessary to clear any latched trips. The trip output of the TPS consists of six- (6) discrete outputs, two- (2) from each processor. This matches the six- (6) emergency trip oil dump solenoids configured in a ‘2-out-of-3 to trip’ arrangement. Field Device Parameter Sensing Assemblies This instrumentation upgrade is a 2-out-of-3, 2-out-of-4 voting design. Each transmitter has a local LED readout, and is plumbed with an isolation valve and calibration port. The transmitters are pre-wired to an on-board junction box with ring lug terminal strips. This proposal includes 2-out-of-3 sensing assemblies for the following functions: The following items are installed in place of the trip block assembly and provide inputs to the TPS. •

Vacuum Pressure. The new panel has three- (3) vacuum pressure measurement devices that provide discrete contacts and analog 4-20mA signals. They may be connected to the TPS as either. Upon sensing a high exhaust pressure (low vacuum) the TPS will issue a trip command.

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Bearing Lube Oil Pressure. The new panel has three- (3) pressure measurement devices that provide discrete contacts or analog 4-20mA signals. They may be connected to the TPS as either. Upon sensing a low bearing oil pressure the TPS will issue a trip command.

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Turbine Thrust Pressure Sensing. While retaining and monitoring the existing oil pressure based thrust-sensing system, this modification incorporates four- (4) independent, pressure measurement devices that provide discrete contacts or analog 4-20mA signals. Two- (2) of the transmitters facilitate monitoring of the active thrust position, and two- (2) of the transmitters facilitate monitoring of the inactive thrust position. The transmitter outputs may be connected to the TPS as either discrete contacts or as 4-20mA signals. Upon sensing turbine thrust the TPS will issue a trip command.

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Turbine Trip Solenoids. This modification incorporates the installation of three- (3) new sets of turbine trip solenoids to facilitate a 2-out-of-3 voting algorithm within the TPS system functionality. Included within this modification is the Auxiliary Governor Function, which will consist of a single set of solenoids. A manual trip handle (Local E-Stop) with an associated limit switch is provided for a local hand trip function.

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Simplex discrete output generated by each TPS processor in a 2-of-3 algorithm for the Auxiliary Governor solenoid function. A set of solenoids that is in same configuration as the turbine trip solenoids.

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Trip Solenoid Testing The six- (6) solenoids (typically) are piped to the throttle valve emergency trip fluid header. They are organized in sets of three- (3) pairs. Each pair is comprised of two(2) solenoids plumbed in series, with the three- (3) pairs plumbed in a parallel configuration. The three- (3) TPS processors actuate the solenoids to generate a 2-outof-3 algorithm. Each solenoid may be independently tested. Pressure switches located between each pair of solenoids indicate when a solenoid has been tripped. Similarly, these pressure switches indicate when a failure of a particular solenoid has occurred. The following permissive conditions must be met prior to testing of any solenoid: •

All TPS processors are operating normally.

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All solenoid panel pressure switches indicate a normal status.

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No TPS processor is sensing a trip and or fault condition.

Tests are conducted from the DCS via a communication link or locally via the HMI. Speed Sensing The Magnetic Pick Up (MPU) bracket provides for primary speed control and electronic overspeed protection will be designed to incorporate multiple new speed probes. Within the confines of a base scope of supply, the vendor should provide four- (4) new active magnetic speed probes for “software” based zero speed detection, measurement, and overspeed protection. •

Three- (3) of these probe slots are dedicated for “software” overspeed measurement and protection.

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Three- (3) of these probe slots are dedicated for “hardware” overspeed protection.

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Two- (2) of these probe slots are dedicated for installed spares.

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Zero speed detection is accomplished directly through the use of the installed “software” based system.

The system senses turbine speeds from ‘0’ rpm through overspeed. All inputs are individually processed through a 2 of 3 algorithm-generating outputs to perform speed control functions as well as overspeed trip functions utilizing a field proven MPU voting scheme. The overspeed trip function will be implemented within control logic and becomes the primary form of overspeed protection.

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Mechanical Overspeed Trip Assembly The mechanical overspeed trip assembly is not very high tech. These systems use a bushing, adjustment nut, plunger, and spring arrangement. As the spring is compressed, the force to overcome the spring force is increased. The weight of the plunger, spring force, speed, and the distance from the plunger to the trip lever defines the trip speed. Since the desired trip speed, the weight of the plunger, and the distance the plunger must travel to strike the trip lever are fixed, the only adjustment that can be made is the spring force. Adding or removing shims, or repositioning the spring compression adjustment nut, changes the trip speed. The only way to change the trip speed is to shutdown the turbine to make the mechanical adjustments. Multiple runups are not unusual. This is time consuming and introduces a potential for human or mechanical error. Owner / Operators have experienced many problems over the years with the setting of mechanical governors. A list of some actual issues follows here: •

Trip plunger improperly machined, a grooved finish on the bore of the plunger guide bushing

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The end of the plunger was flared out preventing the trip plunger from moving. This was the result of a millwright physically pushing on the end of the plunger with a center punch.

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The plunger and guide bushing had a buildup of varnish.

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The installed spring was too strong.

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The installed spring was too weak from either an old spring that had lost some of its force or a spring with too low a spring constant.

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The millwright turned the adjustment nut in the wrong direction.

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Table: Comparison of Mechanical Overspeed Trip System versus Electronic Overspeed Trip System Mechanical Overspeed Trip System General trip speed range, +/- 50 rpm Trip speed will change over time Does not interface with anything Does not provide any trip indication Must have mechanical trip lever interface Oil varnish buildup will keep the mechanical trip plunger from functioning Not fault tolerant Cannot be tested except when uncoupled from the driven equipment, which requires a shutdown Must be initially set in a spin test pit Requires multiple runs of the turbine to adjust the trip set point in the field

Electronic Overspeed Trip System Precise trip speed, digital set point Trip speed will not change over time Provides DCS interface Provides first out trip indication No physical contact with shaft or mechanical trip lever is required Oil varnish does not affect the trip function Fault tolerant System can be tested periodically with a signal generator with minimal or no risk to the operation of the turbine Set by a signal generator Does not require any extra runs of the turbine in the field

Redundant Interface to Valve Positioners The vendor should provide drivers for redundant servomotor coils, expecting the existing servomotors to have dual coils. They should also provide redundant LVDTs, as the LVDT represents a single point of failure in a system that has redundancy built into nearly every other area. This design provides redundancy all the way to the valve. Failure of any module, power supply, servomotor coil, LVDT or wiring will not interrupt operation in any way, and will only result in an alarm for the operator. Electrical Auxiliaries Several auxiliary items should be looked at when performing the upgrade. Vibration monitoring equipment should be added or upgraded to monitor the health of the rotor and associated bearings. Ensure the TCS vendor provides the capabilities to integrate vibration monitoring data into the TCS operating graphics. Adding more sensors to monitor bearing lube oil and metal temperatures, valve metal temperatures, steam chest temperatures and any other temperatures as applicable should enhance temperature monitoring. These indications should be added to the TCS graphics.

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For the purpose of vibration monitoring, a system to monitor the status of the bearings should be made available. It should provide highly reliable turbomachinery information for improved protection. The system should continuously measure and monitor a variety of parameters, which are vital to turbine protection. When any of these parameters begin to indicate weakness in the turbine components, such as imbalance, bearing failures, misalignment, and shaft crack conditions, the operator should be alerted. Engineering information should be provided that includes mechanical modification instructions to install probes in the turbine. The communications to the existing DCS should be a non-proprietary open protocol. Many plant sites have multiple protocols that increase maintenance. The ability to communicate with one common protocol to devices such as generator protective relays, automatic voltage regulators, Turbine Stress Evaluator, vibration monitoring, etc will aid operations and maintenance capabilities. It would be prudent for a customer to chose a vendor that can provide all of the basics plus auxiliaries utilizing a common control platform. This includes generator protective relay and automatic voltage / excitation systems. Having systems that communicate with the same protocol and contain similar hardware will reduce operating, training, and maintenance costs. Conclusion Because of their age, design, and lack of maintenance, today’s steam turbine governor control systems are operating in a manner far different than the original manufacturers designed them. They are also operating in an order of magnitude less efficient in performance than that of similar sized turbines operating with the latest digital controls. Typically these older steam turbines drift, control has a sluggish response caused by multiple individual servo motors connected by antiquated linkages and connectors, or does not operate in a coordinated fashion. These problems are costing your operation and maintenance teams time and money better spent on improving the operation rather than just keeping it running. Find a vendor that can implement an innovative solution for modernizing your steam turbine controls and that can integrate this upgrade into your current or future plant systems using a scalable, standardized, proven platform. Upgrading to a state-of-the-art turbine control system will generate true long-term benefits for operations, maintenance, and service of your steam turbine.

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References API Standard 612, 1995, “Special – Purpose Steam Turbines for Petroleum, Chemical, and Gas Industry Service,” Fourth Edition, American Petroleum Institute, Washington, D.C. API Standard 670, 2000, “Vibration, Axial-Position, and Bearing Temperature Monitoring Systems,” Fourth Edition, American Petroleum Institute, Washington, D.C. Clark, E. E., 2002, “Steam Turbine Overspeed Incidents,” The Hartford Steam Boiler Inspection and Insurance Company. Rutan, C.R., 2003, “Turbine Overspeed Trip Protection,” Lyondell/Equistar Chemical, LP, Proceedings of the Thirty-Second Turbomachinery Symposium. Clark, B.E., 1992, “Steam Turbine Generator Equipment” Westinghouse Electric Corporation. Simatic Catalog ST 70, 2000, “Components for Totally Integrated Automation,” Siemens.

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