Main Steam Turbine Controls Retrofit ISA Final

7/31/2019 Main Steam Turbine Controls Retrofit ISA Final

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EXPERIENCES WITH UPGRADING STEAM TURBINE CONTROLSTO MEET TODAYS POWER MARKET REQUIREMENTS

Frederick W. BlockSiemens Westinghouse Power CorporationProduct Manager, Turbine Control Solutions

[email protected]

Michael J. Weiss

Siemens Westinghouse Power CorporationTechnical Consultant, Steam Turbine Controls

[email protected]

KeywordsSteam Turbine Control Upgrade, Steam Turbine Governor, Steam Turbine Operating Flexibility, FaultTolerance, Turbine Control Availability, Diagnostic Capability, Remote Operation

Abstract

Many older coal steam plants are being operated beyond their planned life span and over a wide

range of conditions in order to be profitable. These plants may have new operating strategies to

accommodate environmental and/or power market requirements. In many cases, while the steam

turbine is capable of meeting these new operating demands, the turbines controller has limited

flexibility and poor spare parts availability, impacting reliability. Many utilities and industria

companies are looking for ways to both extend the life and improve the availability of their existing

turbines by upgrading the turbine control system.

This paper describes recent steam turbine control upgrade experiences using a modern digital contro

platform, specifically designed for the turbine control modernization market. In those experiences

turbine availability was improved by controller fault tolerance and comprehensive diagnostics

Improved flexibility of turbine operation was achieved by upgrading to a full digital platform with a new

operator interface and a secure remote interface to the plant DCS. Some projects had significant

challenges requiring consultation with the turbine engineers to address mechanical issues. Many ofthese coal steam plants continue to successfully operate in the new power generation market.
mailto:[email protected]:[email protected]:[email protected]:[email protected]


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Introduction

As the bottom line tightens and maintenance budgets are stretched, utilities and industrial companies

are increasingly looking for cost-effective retrofit solutions that can extend the life of their plants, as

well as improve the performance of their steam turbines. Achieving this solution can be challenging,

especially when considering mature plants with long histories of modifications, some of which may be

poorly documented. One innovative approach has led to a turbine control system design that isbased on a modular hardware and application software concept. This concept provides a standard

package solution for a wide range of utility and industrial steam turbine frames. Lower cost, tighter

control, higher availability, and easier operability can be achievable while simultaneously improving a

plants ability to respond to changing operating conditions. This paper details some of the added-

value control features available within a modern digital turbine control system.

Control Overview

The look and feel of the operator graphic screens are, not coincidentally, reminiscent of the former

hard panels that existed for many years or decades prior to the retrofit installation. This helps ease

the transition for the operators to the new system. Large analog meters for TG speed and MW are

clearly visible and accessible. Aesthetically pleasing colors and easy to read bar graphs display

valve positions and status, and modes are clearly displayed with illuminated pushbuttons.

Figure 1. Control Overview

The operator screens are user-friendly and not cluttered with superfluous data. This is essential

when adverse plant conditions occur, as operators must be able to react quickly based on accurate

data displays and logical control interface mode selections.


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to inform the operator why the selection is inhibited. An exhaustive search through the system code

to evaluate permissive logic would be therefore not necessary.

Partial Arc Improves Efficiency Saving Money

A turbine that has the capability to operate partial arc configuration can benefit from lower throttling

losses through the HP inlet steam valves and therefore increased turbine efficiency for a given loaddemand. On a recent Westinghouse reheat steam turbine model retrofit, a net 11 MW savings at 50

load was demonstrated by operating in partial arc versus full arc admission. While there are many

variables involved in determining what savings may be achievable, in many cases there is no doubt

that the savings may be significant.

The state of art control system has the ability to transfer between full arc/partial arc modes, also

referred to as single/sequential valve control. This transfer can be made at any time (on line, in

speed or load control) without adversely affecting the rest of the plant. In addition, the transfer can be

paused and continued, or alternated between auto and manual modes, at the operators discretion.

The transfer rate between partial/full arc modes is configurable from on-line operator accessible

configuration screens.

Figure 3. Partial/Full Arc Admission

For those plants without independent HP inlet steam servo actuators, mechanical retrofit packages

are available to upgrade the turbine valve assemblies. Such upgrades can potentially increase

operation and maintenance reliability, due to the installation of new and updated components, and

improve the heat rate efficiency, which can help offset the cost of the modifications in short order.


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Isochronous Control

Many plants maintain processes that are required to be in production 365 days a year. Constant flow

of process steam as well as reliable frequency control for the power that is generated for in-house

use is important in the event that they are disconnected from the grid. Some plants rely upon local

island mode to continue their operations, also referred to as isochronous control. The basic theory is

that a given machine is predetermined to be the swing machine or frequency machine, in the event ofseparation from the grid.

Todays state-of-the-art control system offers the flexibility of being either the load machine

(depending upon the desired plant load to be maintained) or the swing, or frequency machine.

When in frequency control, the speed controller receives a speed target of 60 Hz and the system

holds plant load by maintaining the frequency. If the load demand were to increase, thus lowering

frequency, the isochronous controller is to counter with more flow demand, thereby bringing the

frequency back up to 60 Hz. Of course, if load decreases, and the swing machine sheds load to

maintain frequency, there will reach a point that the swing machine can no longer shed any more

load.

The state-of-the-art control system should be capable of control schemes where the swing machine

transfers its last remaining load to a secondary swing machine, as well as schemes where the load

machine sheds load, so that the swing machine can stay online. Since every plant is different, the

main theme is to make sure that the system is flexible enough to handle all situations.

Coordinated Process/Extraction Control

Depending upon plant conditions, it is sometimes not possible to supply all of the demanded process

steam through a downstream process valve. Once the process valve is completely open, a

coordinated strategy is used to raise the HP exhaust pressure, making more process steam available,

while simultaneously maintaining LP and process steam valve control without controller hunting.

The modular extraction/steam turbine control is able to minimize hunting or PI loop interaction by

using HP exhaust pressure feedbacks in both the process steam and LP demand controllers. The LP

valve controller is driven by a feed-forward function of load demand as well, so it is the LP valves that

share the brunt of the responsibility for this control.


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Figure 4. Process Overview

Dynamic Sequence Diagrams

Due to the complex interactions of some turbine valve flow control schemes, dynamic sequence

diagrams have been developed to assist the operator and/or engineer in visualizing the inherent

nature of the coordinated control.

Using HP Limitations as an example, the turbine addresses improper steam flows by use of four

available HP limiters, which all feed into the HP Valve Reference. The four standard limitations are:

1. HP Limiter: a manual limiter initiated by the operator.

2. Main Steam Pressure Deviation: monitors inlet pressure level because of potential for

water damage to the turbine blading.

3. HP Exhaust Pressure: To compare First Stage Shell Pressure and HP Exhaust Pressure

for steam flow regulation through the HP section of the turbine.

4. HP First Stage Limiter: To compare HP manual and First Stage Pressure.

Visualizing the complex interactions between such an array of process variables would be extremelydifficult, at best. The advantages of the modern control system are fully exploited by utilizing real time

scan rates, powerful computation ability, and high resolution graphics to provide the process engineer

the big picture by way of the embedded Dynamic Sequence diagrams.


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Figure 5. Dynamic Sequence Diagrams

Configuration ScreensEach of the function charts in the process overview diagram can be individually selected for function

specific data or parameter display. For example, a click on the f(x) block provides a plot of the (x)y

function. Each function chart also is easily modified by way of a password protected online

configuration screen. The function chart is process engineer friendly, and highly transportable

between many? units.

There are over 20 password protected online configuration screens with more than 200 parameters

available to the process engineer for machine performance optimisation. Detailed programming

knowledge is not required. This is an essential feature of a system that is designed for operators and

process engineers, not software programmers.

Tuning Screens

Like the Configuration screens, password protected tuning screens are available for all controllers.

These tuning screens have a built-in pushbutton feature that allows the engineer to initiate step jumps

to setpoints. In this way the PI control response can be observed and tuned online, without

jeopardizing the stable operation of the unit. No extraneous equipment (such as a chart recorder) is

required, which can help save time and mitigate potential issues which may be associated with tuning

and commissioning. Since the step jumps are pre-configured, the potential for the engineer to put

too large a transient on the system disrupting boiler operations, or put undue strain on the turbine can

be mitigated.


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Figure 6. Password Protected Online Tuning Screens

Each tuning screen features a control variable (demand in blue), process variable (feedback in red),

control deviation (YE, or error, in brown), and integral output (YI in green). In addition, trends are

automatically displayed for a dynamic visual representation of the control variable being tuned.

The following tuning screens are standard: Speed, Load, Inlet Pressure, Process Pressure, First

Stage Shell Pressure, LP Valve Process, HP Exhaust Pressure Limiter, First Stage Pressure Limiter,

and Valve Tuning screens (HP and LP). Figure 7 shows an example of the actual valve response to

step changes after the built in tuning procedure.

Figure 7 Actual Valve Response Example


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Fault Tolerant Valve Control

The state of the art turbine control also features a high performance, fault tolerant servo valve control

technique with redundant position feedback, redundant coil servo valve and dual controllers. Figure 8

(below) shows an example where one of the LVDT failed without affecting the valve position.

Figure 8 Actual LVDT Failure From Operating Site

Turbine Manual/Turbine Auto

Plant operators require the ability to take over control from the system during unanticipated process

upsets, or in the event that the system or some part thereof should become disabled. In the state-of-the-art-control system, bumpless transfer to manual mode is permitted at any time, and provided that

permissives are met, a transfer back to auto mode. As the name implies, manual mode allows the

operators to directly control the modulating steam valves, via raise/lower commands, bypassing the

automatic control algorithms.

An easy to read tracking meter displays whether or not the manual and auto modes are matched,

verifying bumpless transfer. This tracking meter is another feature of the legacy analog system being

intentionally reproduced in the modern digital system in order to provide the operator a tangible visual

reference point for the manual/auto tracking status.

Auto/Manual Control of Speed/Load/Valve Limiter

Within the main Control Overview screen (Figure 1), operators have access to speed, load, or valve

limiter setpoints. These setpoints can be changed either by raise/lower buttons (manual) or by rate-

controlled target entry fields (auto). Load Governing mode intends that the PI controls never receive


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anything but controlled ramped setpoints, which can be adjusted via password protection

configuration screens.

Figure 7. Automatic Control (Load Control Shown)

In addition to the main steam flow or valve limiter, each valve is equipped with individual valve

limiters, intended to initiate during a valve feedback failure. This feature can allow online device

repair and restoration to service, by a controlled valve limiter response rather than a sudden jump

back into service as many turbine control systems do presently. This can result in a smoothertransition, and ultimately more control in the hands of the plant operators.

Auto/Manual Control of Process Pressure

The same flexibility thats available for auto/manual control of the turbine valves can also allow the

operator to control process pressure either manually or through coordinated control. The

permissives for auto process pressure control are a combination of turbine, load, and exhaust

pressure modes.

Figure 8. Auto/Man Process Valve Control

Online Testing

A feature of the state-ofthe-art modern control system is the ability to perform online testing of

critical control elements and protection functions. Industrial insurance companies frequently require

that many systems be tested to verify adherence to code and safety standards. Therefore, state-of-


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the-art systems should be equipped with the ability to perform a wide range of testing, while the unit is

running, with a low likelihood of affecting operability of the plant. The system described in this paper

incorporates such a wide range of built-in testing capabilities.

Valve Tightness Test

The turbine control system is usually equipped with a valve tightness test routine. The valvetightness test allows the stop valves to be isolated while monitoring turbine speed. Any speed

measurement is indicative of steam flow, which can be indicative of potential steam leakage through

the valve seat. To aid the engineers in their assessment, online speed graphics and valve status is

provided. Speed criteria can be modified for any given turbine based on manufacturers

recommendations.

Safety System Test

The Safety System Test is to verify the integrity of protective trip devices, on-line, using Algorithm

State Machine generated logic. The state-of-the-art control system should physically isolate the safety

devices, so that a true indication of the systems ability to produce a trip signal is generated. The

protection functions to be tested are: vacuum trip, lube oil trip, overspeed trip, and external trip.

Online message displays provide real time status of the testing in progress. The system should be

redundant, allowing for the testing of one channel at a time.

Figure 10. Safety System Test

Overspeed Test

Potential overspeed is a concern with any large rotating machinery. A sound turbine control

protection scheme must accommodate overspeed protection testing by both internal and external

means. Current applicable standards in the United States state that a steam turbine must have at

minimum two independent overspeed protection systems in service at all times. The state-of-the-art


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control system addresses this safety standard, while simultaneously providing the ability to test the

independent overspeed protection systems, on-line.

Figure 11. Overspeed Test

During the external overspeed protection test, whether it is a mechanical bolt or an electronic device,

the internal overspeed trip setpoint (often set at 107% of rated speed, for load rejection purposes) is

moved from 107% to 112% to allow the external overspeed protection device to be actuated. In the

event that the unit fails to trip from the external overspeed device, the internal setpoint of the turbine

control system protection logic on the state-of-the-art control system should trigger a unit trip. Thus,

even during testing, two independent overspeed protection devices would always be present.

Test logic interlocks can help eliminate the risk associated with procedural errors, and an auto speed

target window, with pre-selected slow rate, can provide the smoothest transition to the overspeed

condition. Maximum speed achieved during the overspeed test is also latched onto the test screen

to provide an instant feedback of the test results.

Valve Test

Many OEM turbine maintenance protocols require weekly testing of the steam turbine control valves.

It is typical for many steam turbines to be operated in base load conditions for extended periods of

time, during which multiple control valves may move very little, if at all. Under these conditions, in

combination with degraded or contaminated control oil, some servoactuator mechanisms can become

unreliable or even stuck. The modern control systems test capabilities include an on-line valve test.


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This valve test includes the ability to pause or continue the testing at any point, and also to abort the

test at the operators discretion.

Figure 12. Valve Test

In addition, the test logic allows for load change during the test (in the event of open loop control) as

well as the use of closed loop MW and/or First Stage pressure compensation to maintain a relatively

constant steam flow during testing. This, of course, is critical for maintaining boiler control stability.

The operator is informed via online message displays of required permissives to conduct the test, as

well as status and valve indications as the test is in progress.

Conclusion

As legacy control systems increasingly age, plant operational reliability, and thus economic viability,

can be more seriously impacted. The justification for replacing the legacy system with a state-of-the-

art modular, scalable, open protocol platform, with greater availability and support is difficult to ignore.

With it can come the benefits of overlapping spare parts inventory, training, and staffing, as most

power plant subsystems can now be integrated into the same platform. In an industry where the

difference between success or failure rests on razor thin margins, plant managers must extract the

maximum value from every maintenance dollar that they spend. The benefits inherent in todays

modern control system upgrade provide ample opportunity to bring that value into reality, and thus

directly to the bottom line.

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Main Steam Turbine Controls Retrofit ISA Final

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