3.4 gl for monitoring control protection and automation of shp stations

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STANDARDS/MANUALS/ GUIDELINES FORSMALL HYDRO DEVELOPMENT

Electro-Mechanical Works–

Monitoring, Control, Protection and Automation of SmallHydropower Station

Sponsor:

Ministry of New and Renewable EnergyGovt. of India

Lead Organization:

Alternate Hydro Energy CenterIndian Institute of Technology Roorkee

May 2011



AHEC/MNRE/SHP Standards/E&M Works – Guidelines for monitoring, control, protection

and automation of SHP Oct. 2009 2

3.13 Communication Links ................................................................................................... 193.14 Recommendations for control systems for various categories of MHP & SHPs ......... 21

3.14.1 Micro processor based control for micro hydro power plant (MHP up to 100 KW) . 21

3.14.2 PC based Integrated Generation Controller (100KW to 1000KW) ........................... 213.14.3 Computer Based Control System for Powerhouses (1MW to 5 MW)....................... 22

3.14.4 Computer Based Control System for Power Plant above 5 MW .......................... 24

SECTION-IV

4.0 Protection of SHP generating units 26

4.1 General 26

4.2 Equipment trouble 274.3 Devices used in typical protection system 28

4.4 Criteria of selection of protection system ....................................................................... 333

4.4.1 Requirements of Protection of Turbine................................................................. 334.4.2 Requirements of Protection of Generator ............................................................. 33

4.5 Generator Protection System and Relay Selection ........................................................... 34

4.5.1 Categorisation .............................................................................................................. 344.5.2Transient overvoltage and surge protection .................................................................. 34

4.5.3 Protection for Micro hydel systems (up to 100 kVA).................................................. 34

4.5.4 Protection for Generating Units above 100 kVA and up to 5 MVA ........................... 35

4.5.5 Protection for generating Units above 5MVA and up to 25 MVA .............................. 414.6 GENERATOR CONNECTED IN PARALLEL TO GRID ............................................ 46

4.7 GENERATORS CONNECTED IN PARALLEL ON A COMMON BUS .................... 46

4.8 PROTECTION GROUPS ................................................................................................ 464.8.1 CONTROLLED ACTION SHUT DOWN ........................................................... 46

4.8.2 EMERGENCY SHUT DOWN ............................................................................. 47 4.8.3 IMMEDIATE ACTION SHUT DOWN………………………………………....46

4.8.4 ELECTRICAL SHUT DOWN…………………………………………………..46

ANNEXURE-I ............................................................................................................................. 49COMPUTERISED AUTOMATION AND REMOTE CONTROL OF SMALL HYDRO

POWER PLANT ........................................................................................................................... 49

ANNEXURE-II ........................................................................................................................... 85LIST OF GENERATOR PANEL INDICATION AND RELAYS .............................................. 85

ANNEXURE-III.......................................................................................................................... 86

LIST OF PROTECTION ELEMENTS IN MICRO PROCESSOR BASED RELAYS .............. 86





GUIDE LINES FOR MONITORING, CONTROL, PROTECTION

AND AUTOMATION OF SMALL HYDROPOWER STATIONS

SECTION-I

1.0 INTRODUCTION

1.1 OBJECTIVES

The purpose of this guide is to provide guidance for selection of monitoring,control andprotection system for SHP up to 25 MW by developers, manufacturers, consultants,

regulators and others. The guide includes selection of technology, extent of automation

and monitoring system for different categories (micro up to100 KW, small up to 5 MWand above 5 MW to 25 MW) that is economical, easy to adopt and sustainable feasible

and essential for safe operation.

1.2 GENERAL

The generating units of a small hydropower plant may have its shaft vertical, horizontal

or inclined with the type of turbine selected to suit the site’s physical conditions. Smallhydro turbines may be selected as per site conditions, head and discharge available. Small

hydro-generator are of the alternating current type and may be either synchronous or

induction type. Usually small hydro units up to 5 MW are expected to require minimum

amount of field assembly and installation work. While machine having capacity from 5MW to 25 MW may have slow speed, large diameter and with split generator, stator that

may require final winding assembly in the field.

Mini & micro power stations are generally provided system suiting to these being run

unattended or with few attendants while bigger machines up to 5 MW capacity have more

elaborate arrangement of control monitoring and protection. Machine having capacity upto 25 MW and provision of parallel operation with other systems will have more

comprehensive control, monitoring & protection system.

This guide will serve as a reference document along with available national &international codes standards, guide & books. For the purpose of convenience this guide

has been subdivided as follows:

• Monitoring

• Control

• Protection

1.3 REFERENCES AND CODES

IEEE Std 1020 - IEEE guide for control of small hydro electric power

plants

IEEE Std 1010 - IEEE guide for control of hydro electric power plantsIEEE Std 60545:1976 - Guide for commissioning operation and maintenance of





Hydraulic Turbines

IEC 61116:1992 - Electro mechanical guide for small hydroelectric

installationsIEEE std 1046 - IEEE application guide for distributed digital control

and monitoring for power plants

IEEE std. 1249 - IEEE guide for computer–based control for power plantautomation

IEEE std. C 37101 - IEEE guide for generator ground protection

IEEE std. C 5012 - IEEE standard for salient pole 50 Hz and 60 Hzsynchronous generator and generator / motors for

hydraulic turbine application rated 5 MVA and above

IEEE std 4214 - IEEE guide for preparation of excitation system

specificationANSI/ IEEE std 242:1996 - IEEE recommended practice for protection and

coordination of industrial and commercial power

systems

ANSI/ IEEE std C 372-1987 - IEEE standard electrical power systems device functionnumbers

ANSI/ IEEE std C 37.95 : 1974 - (R1980) IEEE guide for protective relaying of utilityANSI/ IEEE std C 37.102:1987 - IEEE guide for generator protection

The guidelines are based on the following:a) Technology recommended under UNDP-GEF Project for Himalayan range SHP

project. These recommendations were made by AHEC (Alternate Hydro Energy

Centre) as Indian consultant based on specific recommendations of M/s Mead and

Hunt – US consultant; M/s MHPG Group of European Consultants; WorldLiterature review and local experience.

a) UNDP/world bank recommendation for cost effective irrigation based MiniHydro Schemes in India under Energy Sector Management Assistanceprogramme (ESMAP) by standardization of designs and equipment.

b) “Economic Computer Controls for Low Head Hydro” by R. Thapar and D.A.

Perrault; WATERPOWER’85, U.S.A.c) Thapar, Rakesh, et.al, “Microprocessor Controller for a small Hydroelectric

System”, I.E.E. October, 1986.

d) “Microcomputer Based Control and Monitoring Systems”; DIGITEK INC. 11807,

North Creek Pkwy, So. Bothell, WA 98011 U.S.A. – Technical Literature.e) “Small Hydro-Electric – Technology for Economic Development” by O.D.

Thapar, Presented in Eleventh National Convention of Electrical Engineers and

Seminar on Environmental Friendly Electric Power Generation- Nov. 1995,Roorkee.

f) Report on study and design and development of Model SHP based self sustained

projects - E & M Equipment standardization and cost reduction Vol. III (a)prepared by Alternate Hydro energy Centre, IIT Roorkee for Power finance

corporation Ltd. – 2002.

g) Design of al large number of SHP projects for different states and organization.h) Art & science of protective relaying 1956 by MASON, CR





SECTION-II

2.0 MONITORING OF SHP

Monitoring of operating parameters of the generating unit and their auxiliaries is very

important for the life and optimum utilization of available discharge for generation. The efficientrunning of unit requires regular monitoring. The primary input data and generation output dataare monitored periodically. The details of data required for monitoring performance of a

generating station is as follows.

2.1 SYSTEMS FOR MONITORING

2.1.1 Water Conductor System

• Storage level at dam / barrage / weir

•

River discharge• Headrace channel discharge

• Discharge at outlet of desilting basin

• Fore bay level

• Discharge of spillway

• Penstock pressure

• Tail water level

2.1.2 Hydro-mechanical Parameters

• Turbine and accessorieso Pressure and levels in oil pressure system

o Bearing temperatures (oil & pads)

o Oil level in bearing sumps (if provided)

o Cooling water pressure and temperatures

o Clean water pressure for shaft gland

o Vibration in shaft for large machines( optional)

o Status of inlet and other valves.

• Generator and accessories

o Stator winding temperature

o DE/NDE end bearing temperatures

o Cooling water and air temperatures• Transformers

o Winding temperature

o Oil temperature

o Oil level

o Cooling water temperature and pressures





2.2 REQUIREMENTS OF MONITORING SYSTEM

2.2.1 Instrument Transformers & Sensors

i) CTs & VTs

Current and voltage transformers of rated voltage and appropriate ratio, class of accuracyare selected as per the requirement of the system.

ii) Sensors

The sensors for temperatures, pressures, levels and speed are installed at the proper

location.

2.2.2 Indicating Meters

Analogue type of meters, separate for each parameter with selector switches etc were

being used earlier installed on control panels. Now a days digital meters are being used for such

parameters. Digital multifunction meters are now in use, only one meter provides severalparameters on selection, as well as provides routine display.

2.2.3 Temperature Scanners

Digital temperature scanners indicating the temperatures of stator winding, bearing pads,

oil coolers etc. are provided and installed on the generator control panels. These scanners get thesignals from the sensor installed at specific locations preferably through screened cables.

2.2.4 Indicating Lamps

Indicating lamps of suitable colours as per code and practices should be provided on

control panels for indication status of machine and various auxiliaries, pumps, electrical

equipment like breaker, isolator, AC/DC supply system etc. Lists of such indication and relaysare enclosed as Annexure-I&II.

2.2.5 Alarm & Annunciations

The protection system relays and auxiliary relays also provide signals to alarm andannunciation system. A set of annunciation windows are provided on control panels for each

fault clearing relay with accept test and reset facility through push buttons. Alarm and trip

annunciation indicate the fault and advise operating personnel of the changed operatingconditions.





2.2.6 PLC Based System

Recently control of machine and auxiliaries is done through PLC based control system

automatically in addition to manual systems with local and remote facilities. The data is acquiredthrough sensors and operation of machine is achieved on preset values through PC Monitors etc.

The PLC will acquire data from generating units, transformers, switchgears and

auxiliaries through transducers / sensors/ CTs / VTs.Wherever signals are weak, noise level is high shielded cables should be used for

carrying data / signals. For sending output signals PLC will use relays for operating breakers etc

and comparators for giving ON/OFF signal.

2.3 LEVELS OF MONITORING

Normally two levels of monitoring is provided in SHP as per recommendation of IEC

1116. The levels are:

• Alarm

• Tripping

In case of manned power plant ‘alarm’ comes first so as to make the operator alert if nocorrective action is possible then tripping command with indication / hooter and annunciation

will be there.

But in case of unattended power plant direct tripping command will be initiated and shut

off the facility to avert possibility of any damage to the plant.





SECTION-III

3.0 CONTROL OF UNITS OF SMALL HYDROPOWER PLANT

3.1 GENERAL

For small hydro installation simplicity of control system is advised, however, thesophistication of control should be based on the complexity and size of the installation, without

compromising unit dependability and safety of personnel. Simplicity of control is desirable to

keep total cost of installed equipment as well as cost of maintenance, repair and tests ateconomical level. Moreover a simpler system is more reliable as compared to complex one.

3.2 Technology

Up to 1980s, control of a hydro plant’s generating units was typically performed

from governor panel or unit control switchboard. If the plant had multiple units, a centralizedcontrol board was provided. The unit control board and centralized control board using relay

logic contained iron vane meters, hardwired control switches, and hundreds of auxiliary relays to

perform the unit start/stop and other control operations. All the necessary sensors and controlsrequired to operate the unit or units were hardwired to the unit control board and/ or centralized

control board, allowing operator to control the entire station from one location. Data acquisition

was manual.

Modern systems still permit control of the entire plant from a single location.

Modern control rooms utilize the far more cost-effective computer based automation whichimplies (IEEE: 1249 definition) use of computer component, such as logic controllers, sequence

controllers, modulating controllers and microprocessors in order to bring plant equipment intooperation, optimize operation in a steady state condition and shut down the equipment in the

proper sequence under safe operating conditions.

This includes programmable logic controllers (PLC’s) for control system and PC

monitor and hard disc for data display and data acquisition system and distributed computer

control systems with graphic display screens to implement a vast array of control schemes. The

SCADA (supervisory control and data acquisition) control scheme also provides flexibility incontrol, alarming, sequence of events recording, and remote communication that was not

possible with the hardwired control systems. Data acquisition, storage and retrieval is provided

by the computer.

A detailed write up on computerized automation, remote control and SCADA isenclosed as Annexure –I for reference.

3.3 CONTROL FUNCTIONS

There are many functions to be controlled in a small hydropower system. For exampleturbine governor controls the speed of turbine, plant automation covers operations as auto start,

auto synchronization, remote control startup or water level control and data acquisition and





retrieval covers such operation as relaying plant operating status, instantaneous system efficiencyor monthly plant factor.

3.3.1 Turbine Control

This is the speed / load control of turbine in which governor adjusts the flow of waterthrough turbine to balance the input power with load.

In case small plants in the category of micro hydel (100 kW unit size), load controllers

are used, where excess load is diverted to dummy load to maintain constant speed.

With an isolated system, the governor controls the frequency of the system.

In interconnected system, the governor may be used to regulate unit load and may

contribute to the system frequency control. Figure 1 shows the different types of control

applicable to turbines.

Fig. 1: Turbine Control

3.3.2 Generator Control

This is the excitation control of synchronous generator. The excitation is an integral part

of synchronous generator which is used to regulate operation of generator. The main functions of excitation system of a synchronous generator are:

• Voltage control in case of isolated operation and synchronizing

• Reactive power or power factor controls in case of inter connected operation.

The different generator controls are shown in fig. 2.





Fig. 2: Generator Controls

3.3.3 Plant Control

Plant control deals with the operation of plant. It includes sequential operation like

startup, excitation control, synchronization, loading unit under specified conditions, normal

shutdown, emergency shutdown etc. The mode of control may be manual or automatic and may

be controlled locally or from remote location. Plant control usually includes monitoring anddisplay of plant conditions. Different plant controls are given in fig 3.

Fig. 3: Overview of Plant Automatic Control





3.4 Considerations for Selecting Control System

Governor and control systems for small hydro units especially in developing countries

have to be selected keeping in view the following:

i) Traditional mechanical flow control governor with mechanical hydraulic devices iscomplex demanding maintenance and high first cost. Further performance requirements

of stability and sensitivity i.e. dead band, dead time and dashpot time especially forinterconnected units may not be possible with mechanical governors.

ii) The manpower as available for operation is unskilled and further adequate supervisionis not feasible.

iii) Load factors for stand-alone micro hydels are usually low which affects economicviability.

iv) Cost of speed control and automation with electronic analaog flow control governors,unit control and plant control is high. These systems require attended operation and aremostly based on large capacity hydro units. This is making most of the units very costly

and uneconomical to operate. Experience in successful operation of analog electronic

control system in India for SHP is not good.

v) Electronic digital flow control governors can take up plant control functions.

vi) Flow control turbine governors are expensive and not recommended for small hydro

units in micro hydel range. Electronic load control governing system with water cooledhot water tanks as ballast loads for unit size upto 100 kW be used. This will make a

saving of about 40% on capital cost. If the thyristor control (ELC) is used then thealternator needs to be oversized upto 2% on kVA to cope with the higher circulatingcurrent included. Accordingly, in case of small units upto 100-150 kW size elimination of

flow control governors by digital shunt load governor (electronic load controllers) will

make these units economically viable and properly designed will eliminate continuous

attendance requirement.

vii) Data storage function can be added to the digital governors.

viii) The dummy loads in the Shunt Load Governors (ELC) can be useful load system or

can be used for supplying domestic energy needs.

ix) Analog electronic governors and plant controllers are also used for small hydro auto

synchronizing and for remote control and monitoring of system.

x) Digital generation controllers were evolved to take care of speed control, unit controland automation, unit protection and generation scheduling and have been successfully in

operation for over ten years.





xi) PLC based system are reliable and suitable for harsh conditions. These have been inoperation in India and abroad.

xii) Dedicated PC based systems for complete generation control can be easily adoptedfor data acquisition and storage at low cost and can also be adapted to SCADA system.

Customized software is used in these systems which inhibits wide spread use. Futuresystems using PC as controller and for SCADA with open architecture and use of commercially available software is recommended for economy and wide spread use.

Comparison of various options for control systems are given in table 1





Table1. Comparison of various options for control system, including turbine governing supervisory co

S.

No.

Turbine Gov. and

Controller Type

Unit size

kW

Mode

of

operati

on

Suitability Cost including Go

protection, SCAD

Aq., Storage and R

(see note-1)

Turbine

Gov. Unit

control

Unit

Prot.

Data storage

and Retrieval

SCADA

Capital O &

1. Mech. Flow control Gov. 50-100 Iso. 9 At high extra cost Very high Hig

SCA

Grid 9

100-500 &

above

Iso. 9

Grid 9

2. Load control governor 50-100 Iso. 9 Suitable At extra cost Low Low

Grid 9

Do not available

100-500 Iso. See note 3

Grid × Not feasible

3. Analogue, Electronic

Gov. & Plant Controller

50-100 Iso. Suitable At high extra cost Very high cost

Grid

Above 100 Iso. High Moderat

Grid

4. PLC integrated controller

with SCADA by PC

SHP 100 kW

to 5 MW

Iso. Suitable Low Moderat

Grid

5. PLC digital governor with

plant controller and

SCADA with redundantPC

Above 5

MW

Iso. Suitable

See note 2

High Moderat

Grid

6. Data Logger with PLC

load controller

5 to 100 kW Iso. Data not available Low Moderat

Grid

7. PC based integrated

system for governing;

plant control protectionand metering

100 kW to

2500 kW

Iso. Suitable – Indigenous system not available Low Medium

Grid

Notes: 1. Cost normalized with main and backup SCADA system.

2. Dedicated digital controller for Gov. and plant control with PC based SCADA backup.

3. Recommended in conjunction with partial water flow control





3.5 Categorization of Control System

The control system can further be defined by identifying following three categories of control:

Control

category

Subcategory Remarks

Location Local Control is local at the controlled equipment or withinsight of the equipment

Centralized Control is remote from the controlled equipment, but

within the plant

Offsite Control location is remote from the project

Mode Manual Each operation needs a separate and discrete initiation;could be applicable to any of the three locations

Automatic Several operations are precipitated by a single

initiation; could be applicable to any of the threelocations

Operation(supervision)

Attended Operator is available at all times to initiate controlaction

Unattended Operation staff is not normally available at the projectsite

Relationship of local centralized and off site control function as per IEC: (62270-2004)guide in fig. 4 & 5.





CENTRALISEDCONTROL

UNIT 1LOCAL/MANUALCONTROL

USERINTERFACE

STATIONSERVICELOCALCONTROL

UNIT 2LOCAL/MANUALCONTROL

INDIVIDUAL UNIT CONTROLSWITCHYARD CONTROLSTATION SERVICE CONTROL& MONITORINGPLANT REAL POWER CONTROL& MONITORING

AUTOMATIC VOLTAGE CONTROLWATER & POWER OPTIMIZATIONAUTOMATIC GENERTAION CONTROLSWITCHGEAR AND RELAY STATUSREPORT GENERATIONDATA LOGGING/TRENDINGHISTORICAL ARCHIVING

SWITCHYARD

CONTROL

SART/STOP SEQUENCING

SYNCHRONIZINGTRASHRACK CONTROL

BLACK START CONTROLUNIT AUXILIARIES CONTROLGOVERNOR/EXCITATION CONTROL/STATUSUNIT LOAD CONTROLUNIT ANNUNCIATIONUNIT METERING

UNIT RELAY STATUSUNIT FLOW DATA

CONDITION MONITORING

POWER HOUSE

STATION OPTICALFIBRECOMMUNICATIONNETWORK (DUAL)

USERINTERFACE

USERINTERFACE

USERINTERFACE

PLC

PLC

PLC

TO REMOTECONTROL

Fig. 4

LOCAL CONTROL SYSTEM

STATIONCOMMUNICATION

LINK

LOCALUSER

INTERFACE

PROTECTIONSYSTEM

COMPUTERBASED

CONTROL

BACKUPCONTROL

PROCESSINTERFACE

PROCESS(UNIT,SWITCHGEARGATES, ETC.)

Fig. 5





3.6 System Architecture, Communication and Databases

i. Open architecture system should be followed in accordance with IEEE-1249-

1996. Interface or operating standards for the following should comply withISO/IEC 12119/IEEE 802.

Hardware interconnectivity

Time stamping of data,Communications

Operating system

User InterfaceData base

ii. Each of these elements should be capable of being replaced by or communicate withsystem elements provided by other vendors.

iii. The scope of the bidder is not limited to the parts & components explicitly identified

here in and shall have to provide any and all parts/components needed to meet thefunctional requirements laid down herein or are necessary for satisfactory operationof the plant.

3.7 Control Data Networks

Local area networks (LANs) should be configured to IEEE 802.3 (Ethernet) standard.

Commercially available software should be used as far as possible.

3.8 Man-Machine Interface (MMI)

The operator’s station of the station controller (SCADA system) should have an elaborate

and friendly man-machine interface. A 19” or larger monitor should be provided for thedisplay. Provision should be made for connecting a second colour monitor in parallel.

The screen displays should be suitably designed to provide information in most

appropriate forms such as text, tables, curves, bar charts, dynamic mimic diagrams,graphic symbols, all in colour. An event printer should be connected to PC of the

SCADA system. Events should be printed out spontaneously as they arrive. Provision

should be made to connect and use another printer simultaneously. Touch control screen,

voice and other advanced modes of MMI are desired and should be preferred. The entirecustomization of software for MMI and report generation should be carried out. A

window based operating system should be preferred.





3.9 Hardware

Input/output system should have following capabilities.

i. Portability and the exchange of I/O cards from one I/O location to another. Thiscan reduce spare parts requirements.

ii. Availability of I/O cards to be replaced under power. This avoids the need toshutdown an entire I/O location to change one card.iii. Sequence-of-Events (SOE) time tagging at the I/O locations; accuracy and

resolution.

iv. Availability of I/O signal types and levels that support the field device signals to

be used.v. Support of redundant field devices, capability for redundant I/O from field device

to the database and operator interface.

vi. I/O diagnostics available at the card, e.g., card failure indicating LEDs, or throughsoftware in the system.

3.10 Grounding

Each equipment rack in which automation system components are located should beseparately connected to the powerhouse ground mat by a large gauge wire.

Shielded cables should be used for analog signals between the transducers and theautomation system. Each shield should be tied to the signal common potential at the

transducer end of the cable. If there are terminations or junction boxes between the

transducers and automation system, each shield circuit should be maintained as a separate

continuous circuit through such junction or termination boxes.

3.11 Static Control

Equipment should be immune to static problems in the normal operating configuration.Anti-static carpet and proper grounding for all devices that an operator may contact

should be provided.

3.12 Information and Control Signals

Information and control signal for proper control and monitoring will be acquired from

the following main and auxiliary/associated equipment and shall be provided astentatively detailed along with the equipment as out lined in this paragraph. Deviation

will be intimated in the bid 25% spare capacity for inputs and output shall be provided.

The control system shall receive input signals from main equipment such as the turbineor the generator, and from various other accessory equipments, such as the governor,

exciter, and automatic synchronizer. Status inputs shall be obtained from control

switches, level and function switches indicative of pressure, position etc, throughout the





plant. The proper combination of these inputs to the control system logic will provideoutputs to the governor, the exciter, and other equipment to start or shutdown the unit.

Any abnormalities in the inputs must prevent the unit’s startup, or if already on-line,

provide an alarm or initiate its shutdown.

i. Generatorii. Generator field excitation equipmentiii. Generator terminal equipment (Line and Neutral side)

iv. Unit generator breaker equipment

v. Turbine

vi. Governorvii. Generator cooling

viii. Service air

ix. Service waterx. DC power supply

xi. AC auxiliary power supply

xii. Water level monitoringxiii. Fire protection

Following four types of signals are provided between control board and particularequipment

• Analog inputs for variable signals from CTs, VTs, RTDs, pressure, flow, level, vibration

etc.

• Digital inputs provides digitalized values of variable quantities from the equipment

• Digital outputs – command signals from control boards to equipment

•

Analog outputs – transmit variable signals from control to equipment e.g. governor,voltage regulator etc.

3.13 Communication Links

a. Communication links with remote control

Following methods are available for implementing control from a remote location:

• Hardwired communication circuits (telephone type line, optical cables etc.)

• Leased telephone lines

• Power line carries communication system• Point to point radio

• Microwave radio

• Satellite

Metallic circuit in hardwired communication circuits and leased telephone lines, requires

special protection for equipments and personals against ground potential rise (GPR) due to





electric system fault, since the hydro-generator is source of fault current. GPR is also caused bylightning transmitted through power lines entering the power plant. As such suitable mitigation

has to be provided.

Power line carrier including insulated ground wire system can be used for

communications purposes. This method couples a high frequency signal on the power line orinsulated ground wire and is decoupled at an offsite point.

Space radio can be used, utilizing power frequencies and micro wave radio can be

practical if hydro plant owner has an existing microwave system.

b. Communication with control boards

Data and control signals of following equipments will be required to be transmittedbetween control board & equipments.

•

Generator neutral and terminal equipment• Head water and tail water level equipment

• Water passage shut off or bye pass valves gates etc.

• Turbine

• Unit transformer

• Circuits breaker and switches

• Generator

• Intake gates or main inlet valve and draft tube gates

• Turbine governing system

• Generator excitation system

The communication link between control board and equipment should be reliable. Opticalfiber cable, shielded cable and Ethernet are various options

c. Communications with Auxiliaries

Data and control signals of following auxiliaries/ equipments will be required to be

transmitted between control board and equipments.

• Fire protection

• AC Power supply

• DC Power supply

• Service water

• Service air

• Water level monitoring

• Turbine flow monitoring





3.14 Recommendations for control systems for various categories of MHP & SHP

3.14.1 Control for micro hydro power plant (5KW to 100 KW)

Manual control and manual synchronization with ELC is recommended. However,data logger with PLC load controller may also be provided. Recommendations of “Micro

hydel Standard issued by AHEC, IIT, Roorkee” are also to be reffered.

3.14.2 PC based Integrated Generation Controller (100KW to 1000KW)

Integrated governor and plant control system are discussed in “Guidelines for selection of turbine and governing system”.

PC based integrated generation controller capable of following function was developedby M/s Digitek of USA and M/s Predeep Digitek in India for SHP.

• Governor speed control

• Automatic sequencing for start up and shutdown including synchronizing• Automatic sequencing for emergency shutdown

• Data recording and reporting

• Alarm anunciation

• Full remote control and monitoring

• Control via terminal keyboard

• Water level control

• Flexible architecture

• Modular card system

• Ability to communicate with other microprocessor based equipment

• Alarm and status logging

• Data logging at user selected intervals

• Event recording

• Line protection- frequency and voltage

• Generator protection - voltage, current, reverse power, differential, loss of field

PC based system for unit control, governor control and other functions provided for SoblaSHP in Uttarakhand is attached as Fig.-6 is a cheaper alternative but lacks redundancy

which can be provided by spare cards for each type. The scheme envisages

installation of integrated generation controller, generator and line protection and metering

was however provided by conventional meters and electromagnetic relays as shown inFig.-6.





Fig. 6

3.14.3 Computer Based Control System for Powerhouses (1MW to 5 MW)

Most of the small powerhouses in the range have the control room at the same level asthe machine hall. Accordingly the unit control and supervisory control functions can beprovided in the control room.

i) PLC Based System

One PLC integrated controller per unit may be provided for unit control, governorcontrol, plant control, supervisory control and data acquisition and remote control

provision AVR and measuring units and auxiliaries.

Separate controllers may be provided for switchyard, common auxiliaries etc.

Remote/Supervisory control and data acquisition all the unit may be provided by one PC.

The recommended control system is shown in Fig. 7. Manual control facility is provided

on PLC panel.





Fig. 7 -Typical Configuration for Computerized Hydro Station (proposed for SHP)

Note-1 In case machine level and station level is same, manual/automatic control panel

be combined with unit PLC panel

ii) PLC integrated unit controller with PC for supervisory control data acquisition and

remote control facilities for Triveni canal fall SHPs with provision for remote control of

three nearby canal fall power plants have been shown in Fig.-8.

See note





Fig.8 – System Configuration Triveni SHP project (Punjab) (Canal based)

(Provided by M/s ALSTHOM)

3.14.4 Computer Based Control System for Power Plant above 5 MW

3.14.4.1 Functional Capabilities

Functional capabilities summarised below may be provided to the extent economically

feasible.

i. Computer based automation system should permit operation of power plant,switchyard, outlet works, Inlet valves etc. from a single control point.

ii. Manual/Local control should be provided by equipment located near the

generating unit. The local unit computer (PLC) should be part of the equipment.iii. Automatic unit start/stop control sequencing should be part of computer based

automation. Automation system should include capability to provide diagnosticinformation so as to isolate the problem and get the unit on line as fast as possible.

iv. Auto synchronising should be computer based. There is no objection to provide

synchronising function as internal to the automation system. Check synchronising

relay should be provided for security.

v. The computer system shall optimise individual unit turbine operation to enhanceunit operation in respect of following:





a) Efficiency maximization - gate position, flow, unit kW output, unitreactive power output.

b) Minimization unit vibration or rouges running zone - gate position, unit

vibration.c) Minimization of cavitation: Gate position, flow, Hydraulic head, turbine

manufacturers cavitation curve.d) Black start control - this may including starting emergency generator.e) Centralised Control – Individual units, switchyard, station service control,

plant voltage/Var control, water and power optimization; Forebay level

control.

vi. Data acquisition capabilities

vii. Alarm processing and diagnostics

viii. Report generationix. Maintenance and management interface

x. Data archival and retrieval

xi. Data accessxii. Operator simulation training

xiii. Provision of frequency relay for operation in stand alone or in an isolated or

islanded mode, should be made.

A typical block diagram of computer based control system for 2 x 10 MVA Mukerian

Stage–II power house with offsite control is shown in FIG.9. A provision for a

programming station with back up for operation is also included as redundant system.

Fig. 9 – Redundant computer based control system for 2 x 10 MW

Mukerian Stage II with remote control for stage (proposed by M/s BHEL)





SECTION-IV

4.0 PROTECTION OF SHP GENERATING UNITS

4.1 GENERAL

Small hydro turbine-generators should be protected against mechanical, electrical,hydraulic and thermal damage that may occur as a result of abnormal conditions in the plant or in

the utility system to which the plant is electrically connected.

The abnormal operating conditions that may arise should be detected automatically and

corrective action taken in a timely fashion to minimize the impact. Relays (utilizing electricalquantities), temperature sensors, pressure or liquid level sensors, and mechanical contacts

operated by centrifugal force, etc., may be utilized in the detection of abnormal conditions. These

devices in turn operate other electrical and mechanical devices to isolate the equipment from the

system.

Where programmable controllers are provided for unit control, they can also performsome of the desired protective functions.

Operating problems with the turbine, generator, or associated auxiliary equipment require

an orderly shutdown of the affected unit while the remaining generating units (if more than oneis in the plant) continue to operate. Alarm indicators could be used to advise operating personnel

of the changed operating conditions.

Loss of individual items of auxiliary equipment may or may not be critical to the overalloperation of the small plant, depending upon the extent of redundancy provided in the auxiliarysystems. Many auxiliary equipment problems may necessitate loss of generation until the

abnormal conditions has been determined and corrected by operating or maintenance staff.

The type and extent of the protection provided will depend upon many considerations,some of which are:

(1) The capacity, number, and type of units in the plant;

(2) The type of power system;(3) Interconnecting utility requirements;

(4) The owner’s dependence on the plant for power;

(5) Manufacturer’s recommendations;(6) Equipment capabilities; and

(7) Control location and extent of monitoring.

Overall, though, the design of the protective systems and equipment is intended to detectabnormal conditions quickly and isolate the affected equipment as rapidly as possible, so as to

minimize the extent of damage and yet retain the maximum amount of equipment in service.

Small hydroelectric power plants generally contain less complex systems than large

stations, and therefore tend to require less protective equipment. On the other hand, the very

small stations should be typically unattended and under automatic control, and frequently have





little control and data monitoring at an off-site location. This greater isolation tends to increasethe protection demands of the smaller plants.

An inherent part of the power plant protection is the design of the automatic controls torecognize and act on abnormal conditions or control failures during startup. Close coordination

of the unit controls and other protection is essential.

4.2 EQUIPMENT TROUBLE

4.2.1 Plant Mechanical Equipment Troubles

4.2.1.1 Turbines

(a) Excessive vibration

(b) Bearing problems

(c) Over speed(d) Insufficient water flow

(e) Shear pin failure

(f) Grease system failure

4.2.1.2 Hydraulic Control System

(a) Low accumulator oil level(b) Low accumulator pressure

(c) Electrical, electronic or hydraulic malfunctions within the governing or gate

positioning system

4.2.1.3 Water Passage Equipment

(a) Failure of head gate or inlet valve

(b) Head gate inoperative(c) Trash rack blockage

(d) Water level control malfunction

4.2.2 Plant Electrical Equipment Troubles

4.2.2.1 Generator

(a) Abnormal electrical conditions(b) Stator winding high temperature

(c) Low frequency

(d) Bearing problems(e) Motoring

(f) Fire

(g) Excessive vibration(h) Cooling failure

(i) Over speed





4.2.2.2 Main Transformer

(a) Insulation failure

(b) High temperature(c) Abnormal oil level

(d) Fire

4.2.2.3 Generator Switchgear and Bus

(a) Electrical fault(b) Mechanical failure

(c) Loss of control power

4.2.3 General Plant Troubles

4.2.3.1 Station Service

(a) Transformer failure

(b) Unbalanced current

(c) DC System Trouble

(d) Station Air System Trouble(e) Service Water System Trouble

(f) Flooding

(g) Fire(h) Unauthorized Entry

(i) Protection or Control Logic System Malfunction(j) Water level Monitoring System Malfunction

4.2.4 Utility System Troubles

Utility line faults and other abnormal utility system conditions should be detected and the

plant be disconnected from the utility system. Abnormal utility system conditions include thefollowing situations:

a. Ground or phase faults

b. Single phasingc. Abnormal voltage

d. System separation (islanding)

Coordination with the utility is needed in selecting specific protective equipment,

particularly for line fault detection.

4.3 DEVICES USED IN A TYPICAL PROTECTION SYSTEM

There are numerous ways of providing the functional protective requirements of theplant. While standard devices are generally available that can provide the protective functions





required, however each station should have specific design suitable for protection requirementsof the power plant equipment as well as the interconnection.

The following section describes components of a typical protection system that might beapplied to a small hydro plant. Discussions and diagrams are included to illustrate location and

arrangement of relays.

4.3.1 Protective Devices

4.3.1.1 Temperature

A temperature device, possibly incorporating display and contacts for alarm,annunciation and tripping to monitor bearing, stator and transformer winding temperatures.

Resistance temperature devices operating relays can also be used to detect generator stator

overheating.

4.3.1.2 Pressure and Level

Pressure and level switches installed in the turbine air and oil systems, to alarm, block

startup, or trip, as necessary.

4.3.1.3 Over and under speed

Direct-connected or electrically driven speed switches for alarm, control, and tripping.

4.3.1.4 Vibration

Vibration detectors monitoring turbine or generator shaft sections, with alarm and trip

contacts.

4.3.1.5 Water level

A measuring system incorporating level sensors and monitoring equipment, to alarm, trip,or control turbine output on limiting values of headwater or tail water level, or head.

4.3.1.6 Fire

Sensors located in areas where fire can occur and connected to a central fire monitor for

alarm. Small generators usually do not have fire sensors or suppression equipment, since they are

not usually enclosed.

4.3.1.7 Miscellaneous mechanical

Sensing devices are integral to the protected systems, such as automatic greasing system,

wicket gate shear pins, transformer cooling and station sump drainage system.





4.3.2 Protective Relay and Protection System

4.3.2.1 Features of relays

The protective relays stand watch and in the event of failures short circuits or abnormal

operating conditions help de-energize the unhealthy section of power system and restraininterference with rest of it and limit damage to equipment and ensure safety of personnel. Theprotective relays should possess following features:

• Reliability – To ensure correct action even after long period of inactivity and also to offerrepeated operation under sever condition.

• Selectivity – To ensure that only the unhealthy part of system is disconnected

• Sensitivity – Detection of short circuit or abnormal operating condition.

• Speed – To prevent and minimize damage and risk to instability of rotating plant.

• Stability – The ability to operate only under those conditions that calls for its operation

and to remain either passive or biased against operation under all other conditions.

4.3.2.2 Protective Relay Technology

Protective relay technology has changed significantly in recent years. Induction disk

relays for each individual protective function were normally used. Individual solid state static

relays for protective function were introduced in the decade 1980-1990 and IS 3231-1965 was

accordingly revised in 1987.

The old conventional electromagnetic relays were replaced with static relays which are

much faster and maintenance free. These relays are more reliable and sensitive. These daysmicroprocessor based multifunction relays are available which have different protections

elements and therefore, a separate relay for each protection is not required.

4.3.2.2.1Microprocessor based Multifunction Relays:

Microprocessor based multi function relays are now being used. Advantages

of these relays are as follows:i) Self-monitoring of operating status on continuing basis and to alarm when to function.

ii) Multiple protective functions in one relay reduce panel space and wiring end.

iii) Self calibration by software programming

iv) Programmable set point by software programmingv) Interfacing with SCADA will be easy

Microprocessor relaying has gained widespread acceptance among both utilities andconsumers. The relay functions are the same as those in electromechanical and solid-state

electronic relaying, but microprocessor relays have features that provide added benefits.

Microprocessor relays may have some disadvantages, however, so that there are additionalconsiderations when these are applied for protection in SHP.

4.3.2.2.2Benefits of Microprocessor Relays:





The benefits of microprocessor relays include the ability to combine relay functions intoeconomical unit. Where an electromechanical over current relay may be only a single phase

device, a microprocessor relay will often include three phases and a neutral. It could also

include reclosing, directional elements, over/under voltage, and over/under frequency. Amicroprocessor generator relay could include differential, over current, negative sequence,

frequency, voltage, stator ground, and other protective functions.Similarly, a microprocessor transformer relay might combine differential an overcurrentprotection. A transmission line relay could combine multiple zone phase and ground distance

elements, over current fault-detectors, pilot scheme logic, and reclosing. An electromechanical

scheme will normally consist of individual relays for each zone of phase and ground protection,

separate fault-detectors, and additional relaying for pilot scheme logic. These same devices caninclude non-relaying functions such as metering, event recording and oscillography. All of

these functions are contained in an enclosure that requires less space than the combination of

relays and other devices they duplicate.

A microprocessor relay has self-monitoring diagnostic that provide continuous status of

relay availability and reduces the need for periodic maintenance. If a relay fails, it istypically replaced rather than repaired. Because these relays have multiple features, functions,

increased setting ranges, and increased flexibility, it permits stocking of fewer spares.

Microprocessor relay also have communication capability that allows for remoteinterrogation of meter and event data and fault oscillography. This also permits relay setting

from a remote location. The relays have low power consumption and low CT and VT burdens.

They also increase the flexibility of CT connections. For instance, microprocessor transformerdifferential relays can compensate internally for ratio mismatch and the phase shift associated

with delta-wye connections.

All of these features have economic benefits in addition to the lower initial costs and

potentially reduced maintenance costs that microprocessor relays have when compared toindividual relays.

4.3.2.2.4 Disadvantages:

The operating energy for most electromechanical relays is obtained from the measured

currents and/or voltages, but most microprocessor relays require a source of control power.

Another disadvantage is that the multifunction feature can result in a loss of redundancy. For

instance, the failure of a single-phase over current relay is backed up by the remaining phase andneutral relays. In a microprocessor scheme, the phase and neutral elements are frequently

combined in one package and a single failure can disable the protection. Similarly, a

microprocessor generator/transformer package that has both differential and over currentrelaying provided less redundancy than a scheme comprising separate relays. The self-

diagnostics ability of the microprocessor relay, and its ability to communicate failure alarms,

mitigates some of the loss of redundancy. It may also be economical to use multiplemicroprocessor relay.

Microprocessor relays require more engineering in the application and setting of the

relay though less work in the panel design and wiring. The increased relay setting flexibility isaccompanied by an increase in setting complexity that requires diligence to avoid setting errors.





Also, some relays have experienced numerous software upgrades in a short period of time.Microprocessor relays have relatively shorter product life cycles because of the rapid advance in

technology. As a result, a specific microprocessor relay model may only be available for a

relatively short period of time. As a failure may require replacement rather than repair, it may notbe possible to use an exact replacement, which may require more engineering and installation

work. Although less frequent testing may be required, but for testing it requires a higher level of training for the technician and more test equipment than is normally used with electromechanicalrelays in order to obtain the full benefit of all the features of the microprocessor relay. The self-

monitoring capability of these relays is only effective if the alarm output can be communicated

to a manned location such as a control center. Also, the remote communication ability assumes

there is a communication channel available to the relay.

Following annexure are enclosed for ready reference

• Annexure-II - List of SHP Generator panel indications & relays

• Annexure-III - List of protection elements in Microprocessor based relays

4.3.2.2.5 Protection relays for SHP

i) The application of relays must be coordinated with the partitioning of the

electrical system by circuit breakers, so that least amount of equipment is

removed from operation following a fault, preserving the integrity of the balanceof the plant’s electrical system.

ii) Generally, the power transmitting agency protection engineer will coordinate with

the utility protection engineer to recommend the functional requirements of theoverlapping zones of protection for the main transformers and high voltage bus

and lines. The utility protection engineer will determine the protection required

for the station service generators and transformers, main unit generators, maintransformers, and powerhouse bus.

iii) Electromechanical protective relays, individual solid state protective relays, multi-

function protective relays, or some combination of these may be used as

appropriate for the requirements.iv) Individual solid state protective relays and/or multifunction protective relays offer

a single solution for many applications plus continuous self diagnostics to alarm

when unable to function as required. Multi-function protective relays may be cost-competitive for generator and line protection where many individual relays would

be required.

v) When multi-function relays are selected, limited additional backup relays should

be considered based upon safety, cost of equipment lost or damaged, repairs andthe energy lost during the outage or repairs.

vi) When redundancy is required, a backup protective relay with a different design

and algorithm should be provided for reliability and security.vii) Generators, main transformers, and the high voltage bus bar are normally

protected with independent differential relays (above 1000 kW unit size).





4.4 Criteria of selection of protection system

The designer must balance the expense of applying a particular relay against the

consequences of losing a generator. The total loss of generator may not be catastrophic if itrepresents a small percentage of the investment in an installation. However, the impact on

service reliability and upset to loads supplied must be considered. Damage to equipment and lossof product in continuous processes can be dominating concern rather than generating unit.Accordingly there is no standard solution based on MW-rating. However, it is rather expected

that a 100 kW, 415 V hydro machines will have less protection as compared to 25 MW base load

hydro electric machine.

With increasing complications in power system, utility regulation, stress on cost

reduction and trends towards automation, generating unit protection has become a high focus

area. State of the art, micro processor based protection schemes offer a range of economical,efficient and reliable solution to address the basic protection and control requirements depending

upon the size and specific requirement of the plant.

4.4.1 Requirements of Protection of Turbine

Two level protections are recommended as per IEC 1116. Elements to be considered are:

(a) Speed rotation

(b) Oil levels in bearing(c) Circulation of lubricants

(d) Oil level of the governing system

(e) Oil level of speed increaser (if provided)

(f) Bearing temperatures

(g) Oil temperature of governing system(h) Oil temperatures of speed increasers

(i) Oil pressure of governing system

(j) Pressure of cooling water

Immediate tripping is required for a, c, i, and j. While for item b, d, e, f, g and h only

alarm and annunciation is required to alert the operator and take corrective action, but in case

corrective action is not taken, tripping will eventually follow. Applying brakes at a particularspeed (30% of full speed) is done to reduce time to achieve stand still position of machine.

It is recommended two independent devices must be provided for over speed shut downon larger machines. One for alarm mostly at 110% and other for tripping at 140%, specially for

machines which are not designed for continuous run away speed.

4.4.2 Requirements of Protection of Generator

Elements to be considered normally are

a. Stator temperature





b. Over current (stator and rotor)c. Earth fault with current limits (stators & rotor)

d. Maximum and minimum voltage

e. Power reversalf. Over/ under frequency

g. Oil level in bearing sumpsh. Pad & oil temperature of bearingsi. Cooling air temperature

Immediate tripping is required for items b, c, d, e & f while for items a, g, h and i first

alarm and annunciation is required for taking correcting measure and then tripping if correctingmeasure is not taken within permissible time.

It is advisable to provide heating arrangement to prevent condensation in generator.

4.5 Generator Protection System and Relay Selection

4.5.1 Categorisation

In view of the economy and plant requirements generator protection for smallhydropower stations is categorized a follows:

• Generator size less than 100 kVA

• Generator size 100 kVA to 5000 kVA

i) Generator size 100 kVA to 1000 kVAii) Generator size 1 MVA to 5 MVA

• Generator size above 5 MVA

4.5.2 Transient overvoltage and surge protection

Transient over-voltages and lightning surges are controlled by lightning arrestors. Surge

capacitors are provided to restrict rate of rise of surge voltages and their magnitudes. Everygenerator is provided with a set of lightning arrestors / surge diverter of appropriate rating and

generated voltage.

4.5.3 Protection for Micro hydel systems (up to 100 kVA)

Monitoring and Protection as recommend in micro hydel standards be provided.

Micro hydel (100 kVA) may be provided with series over current and short circuitprotection (MCCB), residual current breakers for earth fault protection and surge protection

equipment. A typical 50 kW micro hydel single line diagram showing protection is attached as

Fig. 10. MCCB could be provided with shunt trip coil for providing over voltage; over currentand unbalance load trip as a part of shunt load governor if possible.





kW h

32 A

Surge Protection

LEGEND

81L-Freq Rela y (Low)

81H-Freq Rel ay (High)

27-Under Voltage Relay

62-Timing Relay

LA

Heater Module

Triacs

Controller

Module

F F F F F F

As

Vs

MCCB WithShunt Trip Coil MCCB

81 L

A

27

V

62

81 H

Residual CurrentOperated Circuit Breaker

Feeder-1Grid

A

3kW h

A- Ammeter

F-Frequency Meter

V-Voltmeter

32-Reverse Power Relay

LA-Lightning Arrestor

kWh-Kilo Watt Hour Mete

MCCB-Moulded CaseCircuit Breake r

G

50 kW 415 V

As

A

AsMCB-Miniature Circuit

Breaker

F

or

MCB

Fig.-10.

4.5.4 Protection for Generating Units above 100 kVA and up to 5 MVA

Monitoring and protection with two levels of protection and recommended as follows in

SHP as per IEC-1116.

4.5.4.1 Turbine

In principle, two levels of protection can be specified: alarm and tripping.

Elements to be considered are:

(a) speed of rotation;

(b) oil level in the bearings;

(c) circulation of lubricant;





(d) oil level of the governor system;(e) oil level of the speed increasers;

(f) bearing temperature;

(g) oil temperature of the governor system;(h) oil temperature of speed increasers;

(i) oil pressure of the governor system;(j) circulation of cooling water

Immediate tripping is required for items a), c), i) and j). Items b), d), e), f), g) and h) may

have an alarm annunciated first if the station is manned allowing corrective action to be

taken, but in any case, in the absence of corrective action, tripping will eventually follow.In some cases, braking is used to reduce the time to standstill.

It is recommended that two independent over speed shut-down devices be used on largerunits which might not be designed for continuous runaway.

4.5.4.2 Generator

The following are normally specified.

(a) Stator temperature;(b) Over current (stator and rotor);

(c) Earth fault with current limits (stator and rotor);

(d) Maximum and minimum voltage;(e) Power reversal)

(f) Over/under frequency;(g) Oil level in the bearing sump;

(h) Bearing temperature;

(i) Cooling air temperature.

Immediate tripping is required for items (b), (c), (d), (e) and (f). Items (a), (g), (h) and (i)

may have an alarm annunciated if the station is manned allowing corrective action to betaken, but in any case, in the absence of corrective action, tripping will eventually follow.

Depending on the individual case, heating equipment to prevent condensation may be

required.

It is advisable to consider differential protection when the size of the generator and/or its

environment justifies it.

The instruments and devices generally recommended for monitoring and protection are

as follows: voltmeter, ammeter, wattmeter, energy meter, power factor meter,tachometer, hours of operation counter, synchronizer, water-level and/or pressure

indicator, turbine opening indicator, emergency stop device, short-circuit current

protection, over current protection, reverse power relay, frequency monitor, voltagemonitor, bearing monitor.





Monitoring and control and data acquisition system (SCADA system) can be a part of the

P.C. based digital governor and generation control equipment. Provision of data storage

of one month with 16 MB of Ram memory and a 540 to 850 MB Hard Drive as part of the PC based governing and control system should be provided. This data could be

retrieved on a floppy drive after one month for examination. As the communication linksdevelop the data can also be transmitted via a Modem to a remote point for examinationand supervisory control.

Typical single line diagram for synchronous and asynchronous generators are attached as

figure 11 and figure 12 respectively.

Typical single line diagram for 2×2.5 MW SHP developed by M/S ANDREZ HYDRO is

shown in FIG. 13 for reference





Fig.-11





Fig. -12





FIG.13-A typical single line diagram for 2×2.5 MW SHP( Source ANDREZ Hydro)





4.5.5 Protection for generating Units above 5MW and up to 25 MW

The following protection may be provided by using integrated numerical generator

protection relay on generator, generator transformers and feeders. Back up electromagneticrelays with instrument transformers may be provided as mentioned below:

4.5.5.1 Generator

1. Generator Differential Protection (87G)2. Negative Phase Sequence (46) (Phase Unbalance)

3. Generator Reverse Power Protection (32)

4. Voltage Restrained Over Current Protection (51V)5. Stator Earth Fault Protection (64 G)

6. Loss Of Excitation Protection (40)7. Over /Speed (electrical) Protection (12G)

8. Rotor Earths Fault Protection (64R)9. Over Voltage Protection (59)

10. Fuse failure Protection (97) on PTS

11. Under voltage (27)12. Check synchronizing

Following additional back up electromagnetic relays from different set of CTs and PTs bealso provided.

1. Voltage restraint over current relay2. Stator earth fault

Following Mechanical Protections are proposed

1. Embedded Temperature detector (PT-100) in stator core and in bearing for

indication, alarm, recording and shut down of the unit.

2. Governor oil pressure low.3. Over speed mechanical for normal and emergency shut down.

4. For large generators, fire protections system will use CO2 as the quenching

medium which will operate automatically. Hot spot/ smoke detectors areprovided all around the periphery of generator winding. Bank of CO

2cylinders

with control panel etc. are provided common for all the generators. The individual

pipes let the CO2 enter in the faulty generator and quench the fire. Generator is

isolator from the bus bar and machine stopped. The system is more effective inclosed cycle cooling systems of generators.





4.5.5.2 Power Transformer

1. Generator transformer differential protection ( 87 GT)2. Over current and earth fault protection with high set Inst. Element (50/51,64)

3. Stand by earth fault protection (64GT) on 33 kV side.

4. T/ F Winding Temperature High Alarm/ Trip (49T)5. T/ F Oil Temperature High Alarm/ Trip (38T)6. Buchholtz relay

4.5.5.3 Station Transformer Protection

1. Fuse set on 33 kV side.2. Digital over current and earth fault relay with high set unit on B.T. side. (50/51, 64).

A typical single line diagram of metering and relaying is shown as figure 13 and

figure 14.





52-3

331661132 kV BUS

52-5

DISTRIBUTIONTRANSFORMER

CT

CT

G1

PS

GENERATOR-

52-1

GENERATORTRANSFORMER-1

11-1

DISTRIBUTIONTRANSFORMER

G2GENERATOR-2

52-2

11-2

P.T.

P.T.

P.T.

41G

45G

PS

CT

CT5P10 5P10

PS

PSCT

CT

CT

CT

CT

EXCITATIONCONTROL

CT

CT

L.A.

CT

CORE-1, 5P10

P.T.

64T

CT

64T

CT 5P10

GENERATORTRANSFORMER-2

RECTIFIERBRIDGE

CT

11 KV CIRCUITBREAKER

CORE-2, METERING

CT

41G

TO 33 kV SUBSTATION TO 33 kV SUBSTATION

52-6

ACC.CLASS 1-0

L.A.

87GT

51

87GT

51

87GT

P.T. P.T.

TO P.T.

EXCITATIONCONTROL

TO P.T.

///

DG SET

SATTAION AUX. T/F

PS CLASS FOR BUSDIFFERENTIAL

CT

CORE-1, 5P10

CORE-2, METERING

CT

ACC.CLASS 1-0

PS CLASS FOR BUSDIFFERENTIAL

///

11 KV CIRCUITBREAKER

FIG. 2.3.1 TYPIC





Figure 14





4.6 GENERATOR CONNECTED IN PARALLEL TO GRID

Whenever generators are running parallel to grid, a comprehensive auto synchronizing &Grid islanding scheme will be required. This scheme will help in synchronizing the generator to

the bus and opening the incomer breaker of the plant whenever there is a severe grid disturbance,thus protecting the generator from ill effects of disturbed grid.

• Grid disturbances9 Under-voltage / Over-voltages

9 Under-frequency/Over-frequency9 Rapid fall/ rise of frequency (df / dt),

9 Grid failure or other faults

Generator may not be able to operate below a certain power-factor. At low power-factor,

reverse reactive power flow may damage the generator.

• Grid fault detection9 Over current and directional earth fault,

9 Rapid fall/ rise of frequency (df/dt),

9 Vector surge relay,

4.7 GENERATORS CONNECTED IN PARALLEL ON A COMMON BUS

Whenever more than one generator is operating in parallel, it is necessary to see that the

plant load is equally shared by the generators in parallel. If there is unequal sharing, there would

be sever hunting amongst the generators and eventually this will lead to cascaded tripping of all

generators, causing a total black out. Specific load sharing relays are available in the marketwhich provides the most effective, online load sharing system for generators in parallel.

4.8 PROTECTION GROUPS

The protective relays and devices of generator and turbine are proposed to be grouped

into following four categories for an orderly shutdown of the affected unit with the remaining

generating units and auxiliaries continue to operate.

4.8.1 CONTROLLED ACTION SHUT DOWN

Controlled action shutdown will be initiated by any of the following conditions

• Generator thrust bearing pads temperature very high

• Generator guide bearing pads temperature very high

• Turbine guide bearing pads temperature very high

• Governor OPU oil level low stage-II





• Governor OPU oil pressure low stage-II

4.8.2 EMERGENCY SHUT DOWN

Emergency shutdown will be initiated by any of the following conditions.

• Sped 115% and deflector/ guide vanes/ runner blades apparatus not moved to closing• Deflector etc. fails to close in preset time

• Unit over speed (electrical) > 140%

• Unit over speed (mechanical)>150%

• Stop push button on control panel in control room is pressed

Emergency shutdown system will perform following functions:

• Trip generator breaker

• Stop turbine by governor action

• Trip generator field circuit breaker

• Operate trip alarm in control room

• Energizes emergency solenoid valve in governor cubicle to stop the turbine by bypassing

governor

• Close main inlet valve

4.8.3 IMMEDIATE ACTION SHUT DOWN

Immediate action shut down will be initiated by any of the following conditions

• Generator differential protection operates

• Generator stator earth fault protection operates

• Generator field failure protection operates

• Generator transformer stand by earth fault protection operates

• Over current in stator

• Over current instantaneous protection in the excitation circuit

The immediate action shut down perform following function

¾ Trip generator breaker

¾ Trip field breaker¾

Initiates controlled action shut down stop turbine by governor action¾ Trip annunciation in control room

4.8.4 ELECTRICAL SHUT DOWN

Electrical shutdown system will be initiated by any of the following conditions

• Over current in the excitation circuit





• Generator back up protection operates

• Generator over voltage protection operates

• Excitation failure protection operates

• Reverse power protection operates

• Generator T/F IDMT over current, over current instantaneous & earth fault protection

operates

Electrical shut down system will perform following functions

• Trip generator breaker

• Trip field breaker

• Governor brings the unit to spin at no load





ANNEXURE-I

COMPUTERISED AUTOMATION AND REMOTE CONTROL OF SMALL HYDRO

POWER PLANT

Er. S. K. Tyagi, Consultant,

AHEC, IIT, Roorkee

1.0 INTRODUCTION

1.1 Purpose

This Guide is intended to assist in preparation of technical specification for

finalizing automation scheme for control, monitoring and data acquisition of a small

hydro power plant. The guide includes different type of control, control locations,automation schemes, system architecture, system protocols, network protocols, type of

networks, PLC based, computer based SCADA system, user and plant interfaces, remote

control & power source etc.

1.2 References & Codes

Latest edition of following standards & codes are applicable:

• “IEEE Guide for Control of Small Hydroelectric Plants” ANSI / IEEE standard

1020:1990.

• “IEEE Guide for Control of Hydroelectric Power Plants” ANSI / IEEE standard1010:1991.

•

“Communication Protocol” IEEE Tutorial course 95-TP-103 IEEE Press, NY 1995.• “Hydro Plant electrical Systems” by David M Clemen.

• IEC: 62270-2004-Hydro-electric power plant automation-Guide for computer basedcontrol.

• IEEE-1048-Guide for distributed digital control and monitoring for power plants

(ANS).

2.0 AUTOMATION AND REMOTE CONTROL OF SHP

In a modern hydroelectric power station almost all apparatus are connected withthe plant control system to perform all operations in either manual or automatic mode.

Most of the major apparatus (e.g. generator, turbine and spillway gates) are equipped

with electrically actuated control elements allowing to operate automatically. Manypower stations are controlled from remote locations and these automatic control systems

facilitate unattended plant operation.

2.1 Manual Operation Control

In manual control it is the responsibility of operator to manually perform control

and data acquisition tasks. The quality of data acquisition has been subject to the

limitation of available staff and human error.





The manual control can be local (control located on panel nearest to the

equipment or on equipment) or/and centralized (with in plant at some other place).

This system is not found sometimes to be as efficient, accurate, safe and

consistent as required by the system.

2.2 Semi Automatic Control

For many years, relay logic type automatic control systems were provided. These

systems were limited to unit control sequencing (start/stop) and were not easily changed,

once installed. Plant operators were responsible for manually performing control and dataacquisition tasks. The quality of data acquisition has been subject to the limitations of the

available staff and human error.

2.3 PLC, Computerised Automatic Control

Automation of hydroelectric power plant operations has made it possible to

accomplish data acquisition and control activities like unit startup& shut down sequence,which were previously performed by relay logic. Computer based control and data

acquisition systems have made it possible to acquire and process more data than in past,

so generated reports can keep Plant Engineer apprised of total plant condition.

Computer based automation system also permit operation of power plant,

switchyard and outlet works (spillway gates, bypass gates, valves, fish ways, fish ladders

etc.) from a single control point that can be local, centralized or remote. The singlecontrol point system has many advantages, including reduction of staff, consistent

operating procedures and capability to have all control and data available for referenceduring normal and abnormal conditions.

2.4 Control Locations

2.4.1 Local

Controls are located on the equipment or with in the sight of equipment for all

auxiliary equipment. For generating unit control is located on unit control systeminterface governor control panel. Local control is synonymous to most basic control.

2.4.2 Centralized

In this system controls for all units are brought to a centralized control roomlocated in the plant itself on control panels. Control of all important auxiliary equipments

are also brought to the control panels installed in the control room. All protection,

metering, synchronizing panel and outgoing lines control panels are located in thiscentralize control room.

2.4.3 Off site (remote)

An off site control location is one that is external to plant. It could be located at

switchyard, another place or at some other remote location. The type of control ischaracterized by a greater degree of sophistication in the control them selves. The off site





control of hydro power stations is inter connected via communication link in lieu of hardwired point to point control. Relationship between all these three control location is

shown in Figure-I.

3.0 AUTOMATION OF HYDROPOWER PLANT

3.1 Control Requirements

Basic control requirements are as follows:

• Gathering process information

• Controlling the process

• Protecting and supervising the process

•

Monitoring the process

3.1.1 Gathering process information:

Process information can be gathered continuously or periodically and consists of

control parameter statics information or feed back signal.

Presentation can be visual, recorded, audible or combination of all, strips charts

recorders, analog / digital indication instruments, video display unit (VDU), lamp

indicators and liquid crystal display are some visual information formats. Audiblepresentation may be in the form of bell, gong or tone alerting the operator to an alarmcondition / information.

Process consists of turbine, generator, common auxiliaries unit auxiliaries, D.C.

distribution system, low voltage power, medium voltage power, switchyard, intake byepass and draft tube gates etc.

3.1.2 Controlling the process:

Process information gathered serves two purposes:





i) It is used by automatic control system to perform appropriate control actionsii) It allows the operator to operate the plant in safe reliable, secure and economical manner.

The operator should however, be properly trained to start, stop, load, unload and monitor

the generating units and to control the plants auxiliaries including switchyards, watercontrol system and other ancillary features associated with the project.

3.1.3 Protecting and supervising the process

The protection system is divided in two subcategories:

(a) Electrical protection system covering major plant electrical apparatus and essential

electrical auxiliary systems (e.g. generator, step up transformers, station service electrical

system). Protective systems have progressed from specific purpose electromagneticrelays to specific purpose electronic analog relays to contemporary multipurpose digital

relays.

(b) Mechanical protection is confined to generating units hydraulic turbine, generator andmajor plant mechanical systems (e.g. turbine, draft tube, air depression system).

Protection of “Non electrical” apparatus and systems in the plant are normally assigned to

the plant control system. The control system generally provides tripping signal requiredfor input to the plant protection system in case any of the mechanical systems or

apparatus require removal from service.

The supervisory process involves comparing plant and equipment operatingvalues against designed /set limits. This involves monitoring equipment status as well as

limits. For example ‘on’ or ‘off’, ‘open’ or ‘closed’ position may be incorporated into the

supervisory process with consequential control action.

3.1.4 Monitoring the process

Operating and control parameters can be monitored using display devices at their

respective control board (e.g. turbine, governor mechanical cabinet board). Analog and

digital instruments, VDUs and other devices as mentioned above are used as monitoringequipment. Some display units also permit manual control via touch screens.

4.0 AUTOMATION SYSTEM ARCHITECTURE

4.1 System Architecture

System architecture defines the structures and relation-ships among the components of

hydroelectric power plant automation system, including its interface with operational

environment. Architecture includes hardware components, software componentsnetworks, performance, reliability concepts and maintainability of the automation system.

System architecture for hydroelectric power plant also consider such factors as number,

size, types of turbines and generators in the plant, the plant auxiliary system. A widerange of hardware components, networks software, component and database alternative

are available to configure cost effective architectures to meet the automation system’s

design goals.

Open system architecture offers the advantages in case of expansion, ability to

accommodate changing technologies and immunity to premature obsolescence.





While in proprietary system architecture, taken as part of turnkey automationfrom some vendor, flexibility as explained above is not available.

4.2 System classification:

Advances in computer technology provide users with the choice of variety of

system architecture for configuring hydroelectric automation systems. This guide focuseson systems currently employed or envisioned to find future use in hydroelectric plantautomation applications.

There are two general classification of system architecture used in hydroelectric

plant automation systems:

(i) This class uses proprietary hard wares and software and makes little or no provision for

interoperations with other hardware and software. These are called as closed systemsalso.

(ii) The other system class is an integrated system, with all plant control and monitoring

components having a common data communication hardware & software structures.

These are the open systems which relates to its ability to replace hardware,

modify software and expand system capability without a wholesale reconfiguration of the

control system. Attributes of open systems are interconnectivity of hardware andsoftware, possibility of software and interoperability of application and system. From

practical point of view neither fully closed nor truly open system exists, rather a

combination of systems exist with some ability to communicate or function with othersystems.

Examples of applications and majors components of above two general systemclasses along with traditional supervisory control system are as under:

(i) Traditional supervisory control system

These are hardwired supervisory control systems. Major components are:

• Master station

• Non programmable remote terminal unit.

(ii) Closed system

There are stand alone systems (proprietary, single function controllers) Major

components are:

• Proprietary controllers

• Proprietary operator’s console

(iii) Open System:

The application examples are:

• Hydroelectric plant controllers (systems)• Large scale energy management systems,

• SCADA systems (Microprocessor based)

Major components are:

• Programmable logic controllers

• Networked PCs or work station





• End user programmable remote terminal units

5.0 SOFTWARE CONFIGURATION:

5.1 Customized software (Proprietary)

In the customized software there are several options which are as follows:

(a) Dedicated – The software changes are closed to the end user

(b) Configurable – The software has features that can be changed by the user’s softwaremaintenance personnels. These changes are normally of the form of turning on or off

a feature that is already in the software through a software key or password.(c) Programmable – The software has features that can be changed or added by the user’s

software maintenance personnel.

These software are normally available as part of turnkey automation system and as

such sometimes are called proprietary softwares.

5.2 Commercially available (open sources) softwares

These softwares can be purchased as a part of turnkey automation system or

directly from open source by plant owner. In later case the owner will have to makeprovisions for the installation and configuration of the software. Spread sheets, data basemanagers, operators interface software packages are some examples of such softwares

being used as part of the power plant automation system.

These softwares provide flexibility and has many options. In such case owner

may have support from original vendor, other users or possibly other vendors. The most

common options are as follows:

(a) User configurable: The user has all the documents necessary to change the softwareoperation or to add new code that is linkable to the rest of the software. The user has

the ability to add features or change options, but can not change features in the

original code with out the help of original vendor.(b) User programmable: The user has the source code as well as the documentation for

the software and can modify it as needed or implement his own software to be added

to the system.

(c) Full graphic: The user has the ability to generate pixels and / or vector graphic image

on the displays in any form. The software has sophisticated art work generation and

real time display of these images under system control. Often full graphics areimplemented in a window operating environment.

(d) On line configurable: The features mentioned can be done by authorized person

sitting in front of the online and running system. That is authorized person can change

the configuration of the running system as they wish.

6.0 NETWORKS

6.1 Control level data networks

Control data network are communication structures that conveys data through outthe system. These networks are used for transmitting time tagged measurements and

status input signals to update live databases. The application program outputs, consiststypically of control commands and alarms are then transmitted in turn, over the network





to other data stations that interface directly with the process or that display or reportinformation to the plant operators.

The control data communication network is also used for transmitting sequence of

event data with specified time resolution. The data is recorded or displayed for trend andplant diagnostic analysis. The automation hierarchy, the intra plant network services the

unit and functional group levels. Subnetworks and field buses service the instrumentationand local control levels.

The control data network should be able to support transfer of long messages (e.g.

file transfer) as well as short messages for data acquisition, reporting and control

commands.

The network should be able to reduce operators, technician’s burden to operate

and maintain the over all control and monitoring system. Hot and cold systeminitialization should be achieved automatically or manual command from the control

console.

Power plant Engineer should be able to assess the current status of network, to

locate bottlenecks and other problems and to plan action accordingly.

The network should also be able to transmit specific diagnostic and maintenancetrouble shooting data for status display.

6.2 Device level Data Network

Device is an operating element such as relay contactor, circuit breakers, switch orvalve used to perform a given function in the operation of electric equipment logic.

Field wiring for contact interrogation or control devices

• Hard wired

• Fiber optic cables

Hard wired system should be protected against ground potential rise (GPR), for

which proper shielding of cables is to provided while for fibre optic cables such

protection is not required. Field wiring however, should be protected such that a fault onthese cables does not cause loss of more than a minimum tolerable functionality of the

system.

With the advent of programmable logic controllers (PLC) number of wires needed

for connection is reduced by 80% which improved the reliability and availability of functionality of the system.

6.3 Network Protocol

The protocol implies the methods for packing messages data in the form of bit,

bytes, blocks & packets to communicate between the devices. Just sharing bits & bytes

will not allow devices to communicate successfully. Some situations may require





multiple protocols to be run on the same physical media. This is a common situation withplant LAN.

IEDs (Intelligent electronic device) know what data values are in the message and

where they are placed in data stream. This is part of protocol specification that isperformed by the software that assembles and dissembles the message stream.

6.3.1 Proprietary and standard based protocols and networks:

A proprietary network consists IED connected via some media (standard or

proprietary) using a vendor specific proprietary protocol that will only interoperate with

similar IEDs running the same protocol, proprietary protocols are intended to be “stand

alone”. There may be no need for IEDs on these networks to inter operate with IEDs onother networks. A gateway IED is required to connect proprietary network to other

portion of the plant network, should such a connection is needed.

IEDs can typically communicate on a standard serial communication bus byvirtue of sharing a common messaging protocol such as Modbus, Modbus plus and

DNP3. There are few other protocols that have been implemented by some users with the

help of specific suppliers. These IEDs may be compatible but may not inter operate.Often one IED in the network can interoperate with all IEDs and serves as a gateway.IEDs that support Ethernet can be connected in the same Ethernet network even when different

protocols are used. This is different from standard serial or proprietary networks where all IEDs

on the same network use the same protocol. IEC 61850 is usually considered a protocol that runs

on Ethernet networks.

Local area networks (LANs) should be configured to IEEE 802.3 (Ethernet)

standard.Commercially available software should be used as far as possible.

6.4 Network topology

Network topology is either logical or physical. A logical topology is a way thatdata passes over a network from one IED to the next without regard to physical IEDinterconnection. The physical topology of network maps the IEDs of the network and the

connections between them. There are two major groups of topologies:

i) Point to point: Point to point connection only connects two IEDs together.

ii) Point to multipoint: These networks have several major network topologies forcommunications. Bus Topology

A bus topology has each IED connected to the same physical media as

shown in Figure below:





IED IED IED IED

FIG. 2 : BUS TOPOLOGY

IED

Star Topology

In a star topology such as Ethernet, each IED is connected to special node

at the centre that can be passive, providing a path for message to traverse or

active regenerating electrical signals. Hub simply repeat and message on allports. More intelligent hubs are switches which route the message to the port

where target IED is connected. The arrangement is shown in figure below:

IED IED IEDIED

HUB OR SWITCH

FIG. 3: STAR TOPOLOGY

Ring Topology:

In ring each IED is connected to next with entire network forming a closed

circle. Each IED is isolated from all but two IEDs. Ring networks are lessefficient because data travels through more IEDs before reaching the

destination.

6.5 Type of Networks

Network permit passing messages between end points over a wide range of

distances and provides a messaging service that is independent of message content. Anynumber of different media supports network messaging, network design should be such

that it retains critical function in case of a network failure.





6.5.1 Wide Area Network (WAN)

A wan provides long-distance transmission of data, voice, image and video

information over a large geographical area. A WAN can be owned by utility or WANservices can be leased from telecommunication providers. WAN permits enterprise

access to all modes on the WAN. Normally connections to a WAN are made throughrouter, bridge or firewall to control access to distant nodes such as power plants,substation etc.

6.5.2 Local Area Network (LAN)

A LAN is normally designed for limited geographical area such as power plant,utility substation or an office area. A LAN is considered to be part of facility and is

owned by utility owners.

It is capable of transmitting data, voice, image or video information. On a plantthere may be one or more LANs to logically group devices and functions as well as

control loading and security.

•

It is passive, similar to slave in master slave communication• It waits requests from clients

• Upon receipt of requests, it process them and then sends a response.

The characteristics of a client are as follows:

• It is active, similar to the master in master slave communication

• It sends requests to servers

• It waits for and receivers server replies

Master slave and client server communications are similar. The biggest difference

is that generally there is one master, where as there can be multiple clients.

7.0 Communication relationship models:7.1 Master slave

Master slave communication is when the master controls all of the traffic on the

channel. There are two different types – dedicated master and token passing masters. Dedicated: Polling scheme involve no network contention because access medium isgranted in orderly fashion with energy device taking its turn. With centralized polling

all IEDs are addressable and the master IED will send out messages only addressed tosingle slave. Each device has different address as defined in the protocol being used.

The master communicates to each IED one at a time so as to prevent communication

collisions.





MASTERIED

IED-3IED-2IED-1

FIG. 4: CENTRALISED POLLING

Token Passing

Each IED acts as repeater of message called a token and each IED can be both a

master (requesting data from other) and a slave (sending requested data to other IED).The token may contain some data that is copied by the receiver. If token contain no

data, then an IED can use it and fill in its information in the token.

PLC communication and some other control system use token passing scheme to

give command to IEDs along the bus.

7.2 Client-server modelThis is the most popular model for network application. Each IED on the network

is either client and / or server. The characteristic of server are as follows:

7.3 Peer to Peer Model

There is growing trend in IED communications to support peer to peer messaging.Here each IED has equal access to the physical media and can message any other IED.

Thus each IED is both client and server. This is substantially different than master slave

communications even when multiple masters are supported. A peer to peer network to

provide a means to prevent message collisions or to detect them and mitigate the

collision. On this configuration each IED can communicate to each other in anunsolicited manner.

8.0 SCHEMES OF AUTOMATION

Following schemes are normally considered for automation of small hydro plants.

• Conventional control system

• Computerized conventional control system

• Programmable logistic controller (PLC) system





- Single PLC with manual backup

- Redundant PLC

• PC with PLC based control system

• Computer based SCADA system (Microprocessor controller with SCADA)

Regard less of degree of automation desired, control sequence can be divided in tofollowing parts:

• Pre-start checks

• Auxiliary start

• Unit run, synchronize and load

• Running control

• Unit shutdown

• Emergency shutdown in abnormal conditions

Recommendations:A. 5 KW to 100 KW Data logger with PLC load controller

B. 100 KW to 5000 KW(i) 100 KW to1000 KW PC based integrated system for governing and plant

control(ii)1000KW to 5000 KW PLC integrated controller and SCADA with PC

C. 5000KW and above PLC digital governor with plant controller andSCADA with redundant PC

8.1 Conventional Control

The hardware need to perform above functions in a conventional centralizedhardwired control system which is generally similar to that used for individual local unit

control. This consists of equipment such as control panels with discrete control alarm and

indication devices, dedicated data logging, load and voltage control equipment andanunciators. This equipment interfaces to the units in parallel to the local unit control orthrough the local unit control board. Control circuits are with appropriate inter locks.

8.2 Computerised conventional control system

This type of control systems are used for control of hydroelectric units because of

the speed and flexibility needed to run the real time control algorithms and to manage the

associated data.

The computer system interfaces to the plant and to the conventional control

system via input / output (I/O) interface equipment suitable for operation in the harsh

power plant environment. This interface may be parallel to the hardwired control systemand may operate conventional hard wired control circuits.

It may be desirable to furnish a programming and training console that permitssoftware development and operator training while providing back up hardware for

alternate use when the normal operator interface is out of service. Inter locking may be

provided to permit only one console to be in control at time.





Special consideration must be given to the design of the computer system powersupply, grounding and shielding in view of harsh power plant environment and generally

sensitive nature of computer equipment. Protection from electro magnetic and radio

frequency interference should be provided. Computer equipment may be located incontrolled environments such as control rooms. However they may be located in plant

where extreme of temperature, humidity and moisture is absent.

Batteries of uninterrupted power supply (UPS) are commonly used to provide

reliable power for control system. The capacity and duration requirements are dependant

on the shutdown and operation procedures and critical nature of the unit.

Software development and purchase must be considered easily in the design so

that the hardware will be compatible, software will perform desired control and the

human requirement IEEE Std. 1249 may be referred for greater details on the subject of computer based control.

8.3 Programmable logistic controllers (PLC) based control system8.3.1 PLC

As a result of fast progress in technology, many complex operation tasks have

been solved by connecting PLC and control computer besides connection with

instruments like operating panels, motors, sensors, switches valves and such possibilitiesfor communication among instruments are so great that they allow high level of

exploitation and process coordination, as well as greater flexibility in realizing a process

control system. In automated system PLC controller is usually a central part of a

processor control system. With execution of program stored in program memory, PLCcontinuously monitors status of the system through signals from input devices. Based onthe logic implemented in the program, PLC determines which action needs to be executed

with output instrument. To run more complex process it is possible to connect more PLCsto a central computer.

8.3.2 Control Panels

In conventional control relay logic is utilized and these were connected using

wires inside control panels. The disadvantages of such panels are as follows:

• Too much work in connecting wires

• Difficulty in making changes or replacements

• Difficulty in locating error requiring skillful workforce.

• When problem occur hold up time is indefinite, usually quite long.

With intervention of Programmable Logic Controllers, much has changed in how

a process control system is designed. Advantages of PLC based control panels are asfollows:

• Compared to conventional process control system, number of wires needed for

connections is reduced by 80%.

• Power consumption is greatly reduced because a PLC consumes less than a bunch of relays.

• Diagnostic functions of a PLC controller allow for fast and easy error detection





• Change in operating sequence or application of a PLC controller to a differentoperating process can easily be accomplished by replacing program through a console

or using PC software (not requiring changes in wiring, unless addition of some input

output device is required)

• Needs fewer spare parts

• It is much cheaper compared to conventional system, especially where large numberof I/O instruments are needed and when operational functions are complex

• Reliability of PLC is greater than that of an electro-magnetic or static analog relay.

8.3.3 Process Control System

Function of process control system is watched by input devices (switches sensors)that gives signal to PLC controller. In response to this, PLC controller and signals to

output devices (viz. solenoids, electro magnetic valves, relays, magnetic starters, as well

as light and sound signalisers) that actually control how system functions in assigned

manner. Program for sequence of operation is also entered in PLC memory.

8.3.4 Automation schemesThe two control schemes utilized for small and medium hydro stations are:(i) A single PLC with provision of manual operation as back up system

(ii) A redundant PLC for back up system and other PLC for main control

There are various modification of these two basic schemes which depend on the

individual plant requirement and owners preference. The singe PLC system offers the

advantage of low cost and simplicity and is typically backed up by hard wired system.

With redundant PLC system back-up control and memory are provided by second PLC.The advantages and disadvantages of both systems are given in following table.

S.No. Single PLC with manually operatedbackup Redundant PLC

1. In manually operated backup system for

control the unit output is set at operator’s

discretion. An operator usually keep safety

margin of approximately 10% in headwater

or discharge level to avoid problem such as

drawing air into the system. As a result

maximum generation (KWH) for the machine

is not realized in manual operation.

10% Backup for CPU. The CPU includes

the processor, system memory and system

power supply. Head water level and

discharge control is taken care of by

redundant PLC whenever the PLC is

disabled. With this system maximum

expected generation can be achieved.

2. Less expensive as compared to redundant

PLC

The cost of second PLC exceeds the cost of

manual system.

3. Non-uniform spare parts, spare parts would

have to be arranged for both PLC system as

well as manually operated system. But

manual system being simpler in construction

few spare parts would be required

Uniform spare parts. Only on set of I/O

cards need to be maintained. Items such as

spare relays and control switches associated

with hard wired system are not required.

4. Operator’s familiarity with trouble shooting

hardwired relay system

Trouble shooting is complex for SHP

operator may not be trained for PLC system

trouble shooting (some of the complexity is

offset by the PLC and 1/0 card self

diagnostics now available)





5. Less chance of common mode failure

because the hardwired system is less prone to

surge – induced failure and more tolerant to

inadequate grounds

• Some time instantaneous surges may

causes failure of both PLC

simultaneously owners must insist for

good surge protection system and

effective grounding.

• More over if software is non-standard,

software problems will be common toboth.

In control system all unit protective relays should be independent from

programmable controllers. The independence will allow protective relay system to

function even if PLC fails ensuring the safety of unit & personnel.

For a single PLC scheme with a manual operated back up system it is usually

preferable to have and independent RTD (Resistance temperature detector) monitor andannunciation panel functionally operative during manual operation of the unit. It is also

recommended in single PLC scheme, it may have redundancy for power supply in the

same PLC.

Redundant PLC for supervisory control only can also be considered in case itmeets the requirement of the system.

8.4 PC with PLC based Control System

Modern control systems utilize PCs in conjunction with PLC control. The PCs are

utilized with man-machine interface (MMI) software for control display graphicshistorical data and trend displays, computerized maintenance management systems

(CMMS) and remote communication & control. PLC programming software usually

reside on the PC eliminating need of separate programming terminal to implement orchange the PLC software coding. PC can also be used for graphical displays of plant data

greatly enhancing operational control. Standard Microsoft based graphical display

software packages are available for installation at standard PC. These displays includecontrol display with select before use logic informational displays for plant RTD

temperatures or historical trending plots of headwater, tail water and flow data.

Modems with both dial out and dial in capabilities can be located in either PC orPLC or both to provide offsite access to plant information. These modems may be

utilized to control the plant operation from a remote location.

For plants having capacity up to 1000 KW PLC having integrated governor andplant control system with a PC is recommended while for plants having capacity more

than 1000 KW unit control PLC with SCADA is recommended.

8.5 Computer based SCADA System (Microprocessor controller with SCADA):The complex operating system at bigger power stations require a computer based

SCADA system – computer in place of PLC. Some elements of this complexity aremultiple units, complex reservoir or run-off-river water level algorithms and operation of

number of intake gates, inlet valve, spillway gates, sluice gates and draft tube gates in

conjunction with unit start/ stop sequence for flood conditions. The DCS (Distributed

Computer System) is appropriate for this type of operation because it has ability to handle





large quantities of inputs and outputs quickly, providing operator with real-timeinformation.

8.5.1 System:

Computer based SCADA system use microprocessor based control technologyphysically distributed through out the power house. The separate microprocessor units are

linked together by a number of digital communication paths to form a completelyintegrated control system. The distributed system offers several advantages over acentralized main frame computer type system:

• Improved system performance, as the various distributed microprocessors performdedicated software functions or tasks at the same time (parallel processing)

• Reduced software complexity, with each microprocessor performing its own

dedicated task.

• Modular elements, make the system easily expandable and simplifying component

replacement

Increased system reliability because of reduced complexity and modular structure

which allows most of system to function through the failure of one or more components.

Supervisory control and data acquisition (SCADA) is system operating with

coded signals over communication channels so as to provide control of remote equipment

and to acquire information about the status of remote equipment for display or forrecording functions.

8.5.2 Control Parameters:

SCADA system should be complete with primary sensors, cables analysers/

transmitters, monitors, system hardware/ software and peripherals etc. to monitor/ control

the following parameters.

• Generator stator and rotor winding temperatures• Generator and turbine bearing temperature

• Lubrication oil temperatures

• Status of generator cooling system

• Governor control monitoring of turbine speed

• Generator terminal voltage current KW, KVAR, KVA, KWH, Hz, PF, field

voltage and field current.

• Annunciation for violation of permissible limits of above parameter

• Turbine guide bearing temperature detector

• Generator guide & thrust bearing temperature detector

• Guide and thrust bearing oil level indicator

• Generator winding temperature detector

• Turbine speed

• Generator speed

• Governor oil pumps, oil pressure indicator and low pressure indicator and lowpressure switch

• Cooling water pumps, section and discharge pressure switch / gauge.

• Inlet pressure gauge at inlet of turbine





• Level indicator for level in fore bay

8.5.3 Requirements of SCADA System

SCADA should provide monitoring of parameters listed above. The list may have

additional parameters as per requirement of individual plant. It should be able to control

in grid mode or isolated mode as the case may be. In case of off site control it should beable to provide remote monitoring and control. It should have following features.

• Reliable safe control of unit with very high availability

• Automatic start up, on load control and shut down of units by the control system

• Control of auxiliary equipment

• Remote monitoring of all plant status and alarm information

• Remote normal startup on load control and shut down of machines by controlsystem as well as by operator.

8.5.4 Specifying response time

The processing speed of the computer or computers used in control systemdetermines the over all response time which is very important especially during

emergency situations therefore, when specifying a control system, the plant owner should

take care to define response time speed of control system clearly. Some of the times

related to the response time of computer system are:

• Time duration required to update a graphical display from the instant a fieldcontact changes state

• Time duration from the instant a control is activated at the operator station until

the command is implemented at the field device; and

• Over all time duration to process and log an alarm once it is received at the

computer.

The specification should define the acceptable time durations for each of the

above events in both normal leading and high activity loading scenario. Penalty should be

included in specification if vendor can not meet the response time defined. The computersystem response times should be verified at the factory acceptance test to confirm the

system will operate as required by specifications.

8.5.5 SCADA should have following controllers:

• Unit controller

• Common plant controller/ supervisory control

• Remote supervisory control

8.5.5.1 Unit Controller:

It is microprocessor based / PLC based and is required to perform all functions as

below. It is required to have capability to implement closed loop PID function forgoverning and to perform all monitoring, control, protection and recording functions that

a power plant required independently.

(a) It should monitor and control items





• Turbine wicket gate

• Turbine/ Generator RPM

• Generator power out put

• Generator excitation

• Generator breakers

(b) Automatic unit control modes should include following:• Unit automatic start sequence

• Unit automatic shutdown sequence

• Unit automatic synchronizing

• Unit wicket gate set point control

• Unit load set point control

• Unit flow control

(c) The unit should include digital governor with proportional, integral and derivative

gains. The governor be with in a position loop controlled by speed loop and capableof 0-10% droop. A manual position control should be provided. Following governing

functions should be provided.

• Speed evaluator

• Speed control

• Speed set point adjustment

• Gate limiter

• Start up and shutdown control of turbine

• Position controller for guide vanes with power amplifier for control of servo

valve.

(d) Unit Auto synchronization

The controller should be capable of synchronizing the generator to the bus by

reading the slip frequency (generator-bus) and adjusting the governor speed set point

until the correct slip frequency is obtained while sending voltage raise/lower pulses tothe voltage regulator to match generator voltage to bus voltage. When the slip

frequency is obtained and the generator and bus voltage are equal, the controllershould send a close breaker command when the generator voltage and the bus are in

phase. An additional external sync check relay should also be provided to supervise

the controller close breaker command and the manual close breaker command. Thecontroller should follow synchronization limits in terms of breaker closing angle and

voltage matching condition specified by generator manufacturer.

(e) Shutdown sequence

The shutdown sequence provided by controller should be such that the turbine

generator set from any moving state to a complete standstill with all auxiliariescorrectly shutdown. The unit controller should automatically shut down if the control

system detects turbine mechanical system faults; generator electrical faults or specific

shut down conditions are generated with in system. Following three types of

shutdown to be performed on the turbine/generator set should be provided by thecontroller.

(i) Normal shutdown





A normal shutdown should be initiated by a shutdown command that hasbeen issued by an operator either from the panel mosaic or the supervisory

system locally or remotely. This sequence should allow the plant to be

shutdown in a standard orderly manner. After the plant has completelyshutdown it should return to a state in which it can be restarted again on the

issuing of a startup command.

(ii) Emergency shutdown

An emergency shutdown should be initiated if a failure occurs in a criticalitem of plant, which is likely to cause unsafe operation of plant such as an

electrical trip. The plant should quickly and safely shutdown with lockout to

avoid damage to plant or injury to personnel. The plant should be blockedfrom restarting again until the fault is rectified and acknowledged by the

operator from either the panel mosaic or the supervisory system.

(iii) Rapid shutdown

A rapid shutdown is initiated if a safety trip occurs on the plant. The plant

is rapidly shutdown taking care not to cause unfavorable effects such as

pulsations, backwater surges and suction waves. The plant is blocked fromrestarting until the fault is rectified and acknowledged by the operator.

(iv) Unit start-up sequencing

The controller should allow the unit to be started manually (if all

permissive are met) and bring generating unit speed to synchronous speed.Alternately if automatic start up mode is selected either locally or remotely

then unit should automatically start provided all the start up permissive are

met. The unit controller should allow parameters of the start-up sequence tobe configured to match the turbine generator.

(v) Lockout

The controller should include a generator lockout function. Whenever the

lockout function is on it should inhibit the generator from starting. Any alarm

should be configurable as a lockout alarm. The lockout should be reset with a

command entered on the keyboard. When the lockout is on, it should bedisplayed on the screen annunciator.

(vi) Auto restart

The controller should be capable of automatically restarting the turbine

after certain shutdowns if so enabled and if the lockout is not set. The time to

wait for a restart and the enabling of the restart function should beconfigurable.

(vii) Automatic power control modes





The unit controller when the unit is not under plant control mode shouldbe capable of several forms of automatic power control. The operator should

be able to select automatic power control modes at any time and enter a new

set point at any time. .The available power control modes should meet therequirements of system.

•

Gate position should be automatically controlled to match the wicket gateto a position set point.

• Gate position should be controlled to match the kW output of the

generator to a kW set point. Regardless of the kW set point, the generator

output should be limited by a maximum kVA limit specified duringconfiguration.

• Gate position should be controlled to match a flow set point that is

calculated by the controller from a flow versus gate position curve for the

operating head which is entered during the configuration process.

(viii) Override control

• The controller should provide at least two override controls that whenenabled will take over turbine control from the Automatic Power Controlmode when certain set point limits are reached. When these interim

conditions return to normal, the controller should automatically revert to

the primary automatic power control mode.

• The controller should modulate the turbine output so that the measuredgenerator stator temperature (hottest of the three phases) does not exceed

the Temperature Control set point.

(ix) Reactive power control

The controller should have four reactive control modes, one manual and

three automatic. The generator capability curve should be entered into thecontroller during configuring. All automatic reactive power control modes

should be limited by the generator capability curves. If an operator enters a set

point, that will take the generator outside its capability curves, the reactive

power control program should control reactive power to get as close to the setpoint as possible, but remain within the generator's capability.

• Manual: The controller should provide operator capability, using "raise/lower" keys

on the VDT keyboard and the "raise/lower" switch on the manual controlpanel to control voltage and reactive power.

• Automatic VAR control:

The controller should automatically control the generator output to thatVAR set point set by operator. The generators voltage limit and capability

curve should not be exceeded regardless of the VAR set point.

• Automatic PF Control:

The operator should enter power factor set point from the keyboard and

The controller should automatically control the generator output to that

power factor (leading or lagging) set point set by operator. The generator





voltage limit and capability curve should note be exceeded regardless of the power factor set point.

• Automatic voltage control:

The controller should automatically control the generator output to match

that voltage set point set by operator. The generator's voltage limit and

capability curve should not be exceeded regardless of the voltage set point. • Alarm Annunciation

There should be two types of alarms used by the controller. One type

should be the external alarms from contacts fed into the digital inputs of

the controller and the second, the internal alarms generated by thecontroller. All alarms, whether internal or external, should be capable of

being configured to cause different sequences.

Unit controller should be capable of providing audible and visual alarms

in the event of faults occurring in the power plants. The instant the faultoccurs the relevant fault indicator is activated. All faults have to be

acknowledged by the operators and can only be reset when the fault has beenresolved. On the occurrence of following faults audible warning should be

activated to attract the attention of the plant operators.

(x) Manual control panel

The unit controller should have a manual control panel that bypasses the

processor and allows the generator to be operated manually. The manualcontrol panel should include start relay circuitry that is station battery

powered. Manual switches to trip and close the breaker, turn the field on and

off, start and stop the turbine and raise and lower the voltage should also beincluded. The gate should be capable of manual operation by a potentiometer

that is located on a manual control panel and should be calibrated to position

within 0.1 percent.(xi) Unit Protection

The protection system should be based on the use of discrete

microprocessor based relays with the following features:

• Continuous self monitoring

• Online display of actual values

• Should be capable to communicate with supervisory system through unit

controller. The tenderer may also quote for multifunctional numericalrelay.

8.5.5.2 Supervisory Controller

It should monitor and control the status of power plant, provide automaticunmanned operation, log data, display the process through a mimics, supervise water

levels of reservoir, startup and shutdown of units, control manually control auxiliary and

alarm monitoring. All such control should subject to password-bases security system.Depending on the station requirements, the operator should be able to enter set points for

power output, voltage and power factor. It should also have online documentation and

expert diagnostics, efficiency management and plant management.

(i) Operating Regimes:





The plant should be controlled either manually or automatically under differentoperating regimes. Following operating regimes may be provided.

(ii) Plant efficiency control mode:

In this mode of operation, the automatic control system should maximize theplant's energy production for a given headwater level and river flow. To achieve

this, the system should automatically select the optimum number of units to run incombination with the most efficient unit loading point to dispatch all availablewater for a particular gross operating head. The operator should be able to specify

the order in which units are to be started and stopped by the control system.

(iii) Plant load sharing mode:

In this mode of operation, the control system should automatically adjust the

output of each unit by an equal percentage of rated power output in response to

fluctuations in reservoir level. Load sharing should be the default mode used inconjunction with automatic reservoir level control.

(iv) Reactive power control mode:

In this mode of operation, the control system should automatically adjust theexcitation field current to maintain the output power factor or VARs within a

defined range (i.e., leading or lagging). The operator should be capable of

entering a set range that the power factor or VARS must fall within for each unit.

The control system should maintain the unit's output power factor or VARs withinthis set range unless limited by the generator capability curve or the exciter output

current capability. The system should verify that the VAR set point is an identical

percentage of rated output for all units when used in conjunction with automaticload sharing control.

(v) Operator Interface Requirements:

The controller should use a video display terminal or PC as the main operator

console. It should have powerful graphical user interface to the operators. The

operator should be able to completely operate the plant by typingcommands/function key on the keyboard or by push button on control panel. All

information required to operate the plant should be shown .on the screen. A

printer should be used to print out plant information. Symbols and coloursspecified in the international standard IEC 204 should be used for display.

(vi) Screen display:

The screen display should include all metering, indication and annunciator

information normally displayed on a typical power plant control panel. Thisshould include all metered data such as three phase generator volts and amps,

generator watts, VARS, power factor, speed and frequency. This display should

also show generator stator and bearing temperatures, breaker status, line volts,line frequency, and kilowatt-hours. The time and date should also be displayed

with time to the minute.

Screen data should be updated promptly whenever actual data changes. Alarm and

status information should be updated within one second of actual changes. Analog

data should be updated within two seconds of a change. Calculated value such as





temperature, watts, VARS, and power factor should be updated within fiveseconds of an actual change.

All DC analog readings on the screen display should have configurable scalefactors. All except speed should have configurable labeling on the screen.

The AC scaling should be configurable by specifying WYE or DELTA andmaximum AC voltage and current.

Data shown on the display should have the following minimum accuracies.

AC Voltage 1% of full scaleAC Current 1% of full scale

Frequency ± 0.005 HZ

DC Inputs 25% of full scaleKW, KVAR, PF 25% of full scale

Temperatures + 5 degrees C

(vii) Annunciator display:

A portion of the screen should be dedicated for an annunciator. Alarms should be

displayed in order of occurrence with the oldest alarm at the top of the screen. The

sequence of alarms should be distinguishable if alarms are more than 1/60 th of asecond apart. The display should include space for a least 23 alarms. When an

alarm clears, the alarm below it should move up to fill in the blank space keeping

the sequence. No alarms should be lost. Any alarms that do not fit on the screenshould be save until these is room. Alarms should flash until the acknowledge key

on the keyboard is presses. If the alarm is still on after it is acknowledged, itshould stop flashing but remain on the screen. If the alarm has cleared, it should

disappear from the screen when the acknowledge key is pressed.

The annunciator should display both alarms that are internally generated by the

controller and alarms that are sensed external to the controller. The controller

should be capable of generating a contact closure (option) on selected alarms foruse with a horn or telephone dialer.

(viii) Control status display:

The display should include an indication of the status of the turbine i.e., starting,

stopped, synchronizing, etc...

(ix) Automatic control status display:

The display should show the current automatic control mode, its set point, turbine

gate limit, and any overriding control modes.

(x) DT Keyboard:

The keyboard should be a standard keyboard with upper and lower cases, ten key

numeric pad and at least ten function keys. The function keys should be assignedimportant functions.

The operator should be able to start and stop the turbine from the keyboard usingsimple commands. The operator should be able to enter set points via keyboard,





select any one of automatic power control modes and select any one of reactivepower control modes

(xi) External Interface

Supervisory Controller should have a number of protocol modules which shouldprovide connectivity to other devices including remote terminal units and

programmable logic controllers.

(xii) Event Recording and Data Logging

(a) Data logging

Their should be a provision for a data logging printer at the plant to provide data

logging at adjustable intervals, trouble logs and operator comments enteredmanually at the keyboard. The data logging interval for each printers should be

adjustable by the operator in increments of one minute.

(b) Alarm and status logging

All alarms annunciated on the screen should be recorded on the data log, time-

tagged to 1/60 of a second resolution. Plant status or operational changes should

also be recorder on the data log, time-tagged to 1/60 of a second resolution. Theoperator should be able to enter comments on the log manually through the

keyboard.

(c) kWH logging

Plant watt-hours should be accumulated and recorded on the data log at both daily

and monthly intervals. The integrated power generation controller should have thecapability to accumulate these data by one of two methods: internally, by a

calculation method based on direct monitoring of generator CT and PT inputs, orexternally, by receiving and totalizing counts from pulse initiator output from an

external watt-hour meter.

8.5.5.3 Remote Supervisory Controller

In case of off site (remote) control, identical desk top computer based supervisory

controller should be installed at offsite station. This controller should provide identicalset of screens to that of station itself. The same information is displayed at this controller

almost simultaneously with it appearing on the Supervisory Controller at the power

station. The same level of control is also provided on this remote controller. Using the

detailed screens for the startup and shutdown sequences, remote operator should monitorexactly what is happening in the power station. A big screen should also be installed at

some sutable wall of the remote control center displaying on line data. In case some

generating facility is to be added at later date it should be ensured that there is noproblem in protocol matching.

The controller should have following features from safety and security point of

view:

• It should ignore all unsafe commands.

• Only one operator is able to control the unit at any point of time.

• Multiple authorization levels allow different operators access to different levels of control.





(i) Communication Link

To interface Remote Supervisory Controller located at offsite location to plant

Supervisory Controller at centralized control of plant proper communicationsystem should be installed and commissioned.

The equipment to be supplied should have the facility of transmission of speechand data simultaneously. Data transmission speed should be 9600 bps.

(ii) Software Requirements

The operating system:

The software should run in a priority interrupt driven, multitasking operating

system. The system should provide each task with dedicated random access

memory to allow preemptive scheduling of tasks without loss of information.

(iii) Programming language

The controlling programs should be written in a high level compiled languagewhenever possible for ease in maintenance, with the exception of time critical

tasks which should be written in assembly language. The code should be re-

entrant and employ mutual exclusion techniques to prevent deadlock of resources.

(iv) Standardization The software should reside in non-volatile EPROM memory, which should not

require reloading for routine power interruptions to the controller.

(v) Configurability Configuring of the control software should be accomplished via a menu driven

user-friendly program that will be run on an IBC PC or compatible computer. The

configuring should be able to be accomplished at an area remote from thecontroller and should not prevent operation of the controller during configuring

except during the transfer of the configuring information to the controller.

(vi) Functions The software should allow the operator to examine and modify those parameters

of the control software that will specify the operating conditions and restrictions

of a particular plant. These features should include but are not limited to:- Timings

- Decision paths

- Set points- Equation coefficients

- Enabling functions

- Plant description information

The software should also allow for specifying particular contact inputs, analog

inputs and analog outputs. The software should allow user designation and titlingof contact inputs. Analog scale factors should be set via the configuring program.





(vii) Communications

The configuring information should be communicable with the controller via

standard RS-232C communications protocol. The communication should have theability to be via voice grade telephone communication as well as a direct

connection with the controller.

(viii) Security

The configuring software should provide a means of preventing unauthorized

access to the configuring information. Further it should provide a means of

differentiating three or more security levels of configuring information to createthree or more depths of configuring accessibility.

(ix) Human interface

The configuring program should be "user-friendly" in that it should be menu

driven and should be operable by non-technical personnel.

8.6 Physical and Environmental

(i) Physical

The equipment should be constructed on a modular basis, using plug-in

connection. The controller should be suitable for mounting in a standard 19-inch

wide rack, with a minimum depth of 24 inches. Input/output termination cabinetsshould be internally labeled, to permit ready identification of the incoming and

outgoing wiring. The equipment should be of self protecting against surges thatmay be generated on power supply bus by contact operation, circuit resonance,

etc. External connections should utilize modular screw terminal blocks which

should be should be suitably mounted and readily accessible. Each terminaldevice shall suitably identify all conductors. All wiring should be clearly marked

and so designated on the drawing to permit identification for maintenance. Wire

not colour coded should be identified by a wire number marker on each end. Allcables and jacketing material should be oil, moisture, and heat resistance

thermosetting compounds under operating conditions. Controller AC power

connection should be a standard NEMA PI5-5 plug configuration.

(ii) Environmental

The controller and video display should be capable of withstanding the

environmental conditions of the site of plant during air condition failure.

(iii) Power Requirements

The controller should use standard wall outlet AC power, however an inverter

should be supplied that is powered from the station battery to provide AC power.The controller including VDT, DTC, printer, and modem other peripheral

equipment should operate from a 250 VA inverter.

9.0 USER AND PLANT INTERFACES





9.1 User interfaces

The most critical interface for a power plant automation system is the User

Interface (UI). The plant interfaces discussed later in this clause are important to theautomation system in order to perform effective monitoring, annunciation, control, etc.,

but the UI is crucial to the success of the system. If the operator is not able to use thesystem easily and conveniently, the system will never be used properly or costeffectively. The operator's needs are critical to the successful operation and use of a

power plant automation project. UIs offering the look and feel of a personal computer

may be desirable to reduce special training.

In order to make the system acceptable to the operations personnel, care must be

taken in the selection of the hardware and software used. The hardware options are

numerous for input and output devices as well as the workstations to be used.

9.1.1 Input devices

Input devices are not mutually exclusive and may be combined to incorporate desiredfeatures. Typical devices include the following:

a) Trackballs. Pointing devices for menu driven software. Trackballs are normally

used in conjunction with a standard ASCII keyboard and/or numeric keypad and

occupy very little desktop space.

b) Mice. Similar to track balls, they are normally used in conjunction with an ASCII

keyboard arid/or numeric keypad. A mouse requires more desktop space than a

trackball since the mouse must be moved in order to move the cursor on thescreen.

c) Light pens. A pointing device for menu-driven software. Light pens normally usean ASCII keyboard and/or a numeric keypad for data entry and require no desktop

space.

d) Keyboards. Normally installed on all workstations for data input and systemcontrol. Desirable features for keyboards and numeric keypads include standard

key layouts and tactile feedback. They need to be well constructed to withstand

continuous use. They should be waterproof and dustproof. Keyboards usinglayouts similar to the familiar PC will minimize the chance for confusion arising

from the use of a nonstandard keyboard.

e) Touch screens. Useful for cursor positioning but not well suited for data entry.

f) Speech recognition. This input technique is a leading edge technology. It hasmany disadvantages at present such as speaker dependency, large error or

misinterpretation rates, large memory needs, and extensive processing time.

9.1.2 Output devices

As with input devices, various output devices may be combined to incorporate

desired features. Some typical devices are as follows:a) Printers. These devices range from dot matrix units to letter-quality line printers

in both black and black-plus-color models. They are used for hard copy output of

the computer data for reports or historical records.





b) CRT screens. These output devices are on most UI systems and are the primaryoutput device for the computer. They range from small monochrome units to large

color units with millions of color combinations.

c) Speech synthesis. Provides the operator with a phonetically-based audiblemessage output.

d) Mimic boards. Graphical displays or map boards used to represent theconfiguration and data of the plant or system. Mature technology units range frommanual displays with movable parts to fixed displays with lights to indicate

equipment status. New technology units include displays of system data in

graphical form and large projection screens with computer generated displays.

9.2 Plant Interfaces

The plant to computer-based control system interfaces are important to thesuccess of the automated hydroelectric power plant's control system. There are many

types of hardware interfaces, each with specific requirements that must be addressed as

the system is designed, installed, and tested.

9.2.1 Types

Examples of plant interfaces include analog transducer signals, dry contacts (i.e.,contacts without sensing voltages) and digital data. This clause covers several generic

types, however, installations may have special application requirements to meet unique

concerns. This discussion addresses the analysis process for any plant interface.

9.2.1.1 Digital, contact, and pulse inputs

Digital or contact inputs should meet minimum criteria for operations at the

voltages and current loads anticipated. The current required to drive the input circuitry

should be adequate to ensure false indication changes do not occur due to noise. Thecurrent should be as low as possible to conserve power and reduce heat generation.

Wetting voltages (e.g., those voltages required to sense the status of dry contacts) may be

provided by the control system or the field device.

Contact bounce in the input signal can cause erroneous data in the system. Digital

inputs should have filters to detect only sustained input signals. These filters may be in

the hardware or the software. Filters must be selected in accordance with time tagaccuracy. Simple low-pass filters can introduce undesirable delays. Voltage levels for

logic detection should be sufficient to prevent erroneous readings.

Digital inputs may also serve the functions of pulse accumulators or counters.

This function is normally in software or firmware at the I/O. Accuracy, counting, and

pulse accumulation rates should be sufficient for the intended use.

Another variety of digital inputs comes in the form of a parallel (e.g., binary

coded decimal) data. The quantity of wire conductors, noise immunity, and hand shakingrequirements should be considered when making accommodations for these inputs.





Serial digital inputs (e.g., EIA RS232, RS422) are frequently used as an interface

to newer transducers.

Digital input status indicators, often LEDs, may be provided. These indicators

ease I/O and control circuit troubleshooting.

9.2.1.2 Digital and contact outputs

Digital or Contact outputs provide data and control contacts for external circuits.

These contacts must have sufficient current and voltage rating for the external load.

These ratings must often be considered in total for a given card or group of I/O as well asfor individual circuits. Wetting voltage is typically provided by the external circuit. The

ability of the solid-state devices in the output circuitry of the I/O to absorb the required

current (without thermal instability of the devices) is a function of temperature (heatgeneration).

Where higher current ratings are required, interposing relays are typicallyinstalled. The current ratings are then those of the interposing relays.

Digital outputs may be latched, momentary, or maintained. These functions may

be implemented in software or in the output relay. Digital output status indicators—usually LEDs – may be provided, similar to those on input I/Os.

The failure state of digital outputs should be defined and specified. Digital outputfailure may be critical in some applications.

9.2.1.3 Analog inputs

Analog inputs may be low-level (e.g., 0-1 mA dc, 4-20 mA dc, 1-5 V dc, etc.)

current or voltage, resistance, or thermocouple signals. Resistance or millivolt(thermocouple) inputs may be scaled to engineering units by the I/O processor, or a

separate RTD or thermocouple to current or voltage converter located with the I/O.

The I/O is often capable of providing the loop power supply for analog inputs.

Voltage, tolerance, stability, and loading should be considered.

Scaling accuracy, resolution, deadband, and thermal stability should all bespecified to meet the needs of the applications. Thermocouple and RTD replications

should meet the standard accuracy for these devices. Open thermocouple detection is

often desirable. Common and differential mode rejection ratios should also be specified.

When multiplexing technology is used, the multiplexing hardware should be

solid-state and not electromechanical. Multiplexing schemes must be fast enough toensure that the most recent values are available when required for all control loops.

9.2.1.4 Analog outputs





Analog outputs are typically low-level voltage or current. Accuracy, resolution,deadband, and thermal stability should all be specified. Similar to digital outputs, the

condition or value of analog outputs upon failure may be critical in some applications.

9.2.1.5 Analog-to-digital/digital-to-analog conversion

The accuracy of any analog input or output depends on the conversion betweenthe computer's digital data system and the analog information. The conversion is typicallyperformed by multi-bit A/D converters. Conversion accuracy and resolution are a

function of the number of A/D converter bits and I/O amplifier design. Further, the

accuracy is affected by temperature-induced drift. Thus, A/D resolution, input accuracy,

and temperature stability should all be specified.

9.2.1.6 Field devices and field bus standards

Another major source of interface signals are those originating from intelligentelectronic devices (IED) and intelligent field devices (e.g., a field device capable of

measuring more than one parameter and transmitting the measured parameters over one

pair of wires.

9.2.2 Sources

The sources of information to be interfaced to control systems are numerous and

not all are covered in this clause. The most common ones are highlighted, as follows:a) Digital Input Signal Monitoring.

Usually accomplished by sensing the state of relay contacts using the station

battery or a voltage supply to detect the opened or closed status of the contact.The output devices are normally solid-state or electromechanical relays that are

energized or de-energized by the control system.b) Analog Input Devices.

Normally transducers that convert potential transformer (PT) and current

transformer (CT) signals to quantities such as megawatts or megavars. In existingplants, control system analog outputs may drive display panels or strip chart

recorders for operator observation.

c) Parallel Input Devices.Usually shaft encoders or digital panel meters. The output devices are digital

panel meters or process controller modules. These interface sources are in many

cases bidirectional, i.e., they are both input and output devices.

d) Serial Sources.Normally bidirectional devices with built-in intelligence, providing both input and

output capability. The devices consist of smart watthour meters, shaft encoders,

temperature transducers, etc.

9.2.3 Input/output protection

All inputs and outputs should be specified to withstand the Surge WithstandCapability (SWC) test, -as described in IEEE C37.90.1-1989, without any false

operations. The SWC test has proven to be a reliable means to identify noise problems

similar to those found in a hydroelectric powerhouse.





9.2.4 Collection process

The data collection process involves all of the aspects discussed above as well as

some considerations that are internal to the control system as opposed to the interface

itself.

9.2.4.1 Scan rateThe scan rate deals with the rate at which the data is moved from the interface tothe data base or from the database to the interface.

9.2.4.2 Archival rate

The archival rate of the control system is normally the rate at which data is stored

for long-term, historical purposes. This rate varies dependent on data type, in order tosave storage space, retrieval time, and analysis efforts. For example, the archival rate for

temperature data does not need to be as often as that for electrical data.

10.0 REMOTE CONTROL OFF SITE CONTROL

Remote control of hydroelectric plant means controlling activities of a plant from

off site control centers. Personnel at such control centers are responsible of operatingseveral power plants and substations. Some of the control functions performed from such

control centers are:

• Periodic MW & MVARs adjustments to maintain power system operation in

accordance with grid requirements as per guide lines of system control.

• Maintain generation reserves to assure power system stability as per guidelines of system control.

• Energy interchange scheduling

• Automatic generation control, including time error control and frequency control(in coordinative with area system control centre).

• Hourly load forecast

• Transmission line loading (system power flow)• Power export control adjustments.

Remote control can be automatic or manual with duplication of local controls atremote location for desired operation at that site control logic system can be provided by

hardwired relay logic programmable logic controllers, microprocessor based system or a

combination of these. Interlocks are required at the local site to prevent improper remotemanual operation. Remote control and indications may be established by the use of

“supervisory control” equipment, using one of the modern communication means totally

automatic start & slop initiation is possible from remote location. However unattended

operation requires that special attention be given to fail safe characteristic of control

system.

10.1 Control requirement:

Initiation and control functions are listed below. The items installed will vary

according to size of plant, method of system operation and economics.

• Start and stop sequence initiation

• Breaker operation – open/ close





• Motorized excitation or voltage regulator setting rheostat to allow remote settingof field current and generator terminal voltage.

• Governor control and flow control device position (guide vanes, blade angle or

nozzle or valve)- speed – no load

- Best efficiency- Position (guide vanes, blade angle, nozzles or valve)- Unit auxiliary system

- 10.2 Instrumentation requirements:

• KW output per generator

• KVAR output per generator

• KWH output per generator field voltage and current synchronoscope indication

• Generator voltage, current and frequency

• System voltage

• Head water level

• Tail water level, when required• Turbine flow control devices (guide vanes, blade angle, nozzle or valve)

• Status of bye pass, sluice or spillway gates

Transducer or signal transmitters are provided either at the control board or at theequipment.

10.3 Status / Alarms requirement:

• Ready to start

• Breaker position (No alarm if manual operation only)

• Intrusion alarm

• Fire alarm

• Emergency station alarm (immediate response)

• General station alarm (can be differed for some time)

• Trash rack differential pressure alarm

• Unit stop when not required

• Unit turning when not required

• High bearing temperature

• Loss of lubrication or cooling or both

• Low hydraulic system oil pressure

• High or low water levels

• Incomplete start or stop sequence loss of power

10.4 Communication Links:

Following communication methods are used for implementing control from Remote site:

• Hardwired communication

- Telephone type lines- Fiber optical cables

• Leased telephone lines





• Power line carrier communication system (PLCC)

• Point to point radio at approved frequency

• Microwave system

• Satellite

For items of 1 & 2 arrangements of special protection for equipment and personnelagainst ground potential rise & lightening surges are essential.

It is seen that optical fiber cable, PLCC, Satellite communication links are the mostpreferred options as these are more reliable.

11.0 SITE INTEGRATION FOR AUTOMATION OF EXISTING PLANT

Before taking up automation of existing plant it is necessary to study site

conditions and ensure that interfaces and other circumstances are compatible with proper

operation of the automation system some features requiring study for automation are as

under: -

11.1 Existing contact output:Most automation systems include large numbers of contact status point inputs. These

contact can be found in:

- Protective relays

- Manually operated control switches- Level switches

- Position switches

- Other devices.

The contacts should be used directly as inputs to automation system. It is

advisable to avoid input through auxiliary relays. Sometimes contacts in protective relays

are connected in parallel with annunciation equipment. In such case care should be takento avoid any sort of interference between automation system and annunciation equipment.

In case one side contacts is connected to power source from station battery, theautomation system should provide electrical isolation between the inputs to prevent sneak

paths between inputs when either side of the battery is disconnected from one of them.

11.2 Existing Transducers:

An automation system can be configured to adapt to any electrical signal as input

but it is preferable to have standardized inputs. The accuracy of existing transducers

should be studied to ascertain that they most system accuracy requirements. The most

commonly used transducers provide O - + port) signal as an output but transducersproviding 4-20 mA signal are also used by manufacture different transducer outputs

require different input circuits on the automation system. It is therefore, preferable tohave minimum transducer outputs to have less complexity in automation system. It will

make it easier to add or reconfigure the inputs after the equipment.

11.3 Existing control output points:

The functions of output points are:





- Close /trip- Raise / lower

- Start / slop

The characteristic of each output point supervised should be determined. The old

break trip circuits, speed level motors require high level inductive current to be switchedas such output circuits must be capable of reliably switching this current through out thelife of automotive system alternatively interposing auxiliary machine tool type relays can

be used on such outputs.

11.4 Grounding

Each equipment rack of automation systems is required to be separately

connected to the power house ground mat. During power system fault conditions, a large

potential rise can occur between different locations with in power house due to largecurrent flowing through ground.

This potential rise will appear between different components of equipmentcommunication circuit connecting different components must with stand this potential

rise as such with stand value of maximum potential rise for links must be specified. The

use of optical fiber cable as communication link between equipment is one way of

solving this problem. Shield ties on transducer end are used on communication cablesbetween transducers and automation system.

11.5 Power Source

11.5.1 Battery set with charger

Normally a battery set with automatic float rectifier type battery charger poweredby station AC is provided to feed critical load such as protection and control circuits and

devices as D.C. source is more reliable.

An evaluation (as described in IEEE Std 485-1983) should be performed to ensure

that station battery is having enough capacity to operate automation system along with all

other D.C. loads for specified time periods (half an hour is considered adequate in case of station AC failure). The chargers must be capable of supplying D.C. system load while

charging up the battery. If the evaluation shows that larger batteries or chargers are

required, consideration should be given to it for improving automation system efficiency.

Reducing other D.C. load is other option.

Some components of automation system operate on AC power since AC power

source available at power house is not considered very reliable providing inverter toconvert power from D.C. station battery to A.C. power is considered reliable option.

Some automation features like sequence of event recording operating on A.C. are vital

and can not be afforded to be missed as such provision of inverter become inescapable.Inverter, however, should include a bump less static switch with automatic transfer of

power source for the automation system to the station A.C. power source in the event of

inverter failure. Also the inverter should be designed to produce an A.C. output withwave form deviation and wave form characteristics consistent with the requirement of





supplied load. Appropriate failure detection and alarming should be specified in theinvestor.

In case of large power stations two sets of batteries of full required capacity arerequired to make availability of D.C. more reliable.

UPS of proper capacity are preferred for SHP as these require less maintenanceand are considered more reliable.

11.5.2 Uninterruptible Power Supply System (UPS)

Uninterruptible Power Supply System in SHP are required to provide electricity for

computerized control and data acquisition system, communication system etc. when

normal plant power system fail. As per IEEE: 944 – Recommended practice forapplication and testing of uninterruptible power supplies for power generating stations;

UPS systems are used to provide electricity for essential loads when normal plant power

system fails. Loss of power to such loads as the plant computers, communicationnetworks, security system and emergency lights.

UPS SYSTEM

DC BATTERY (48/110V)

FUSE

FLOATED BOOSTCHARGER

AC FROMSTATIONSERVICE

D.C. BUS

D.C. FEEDERS

FEEDERBREAKER

TO COMPUTERCONTROL SYSTEM

TOEMERGENCY

SUPPLY

AC-220V FROMSTATION SERVICE

MCB

Fig. 3.3 Typical DC system for SHP up to 3000 kW

UPS system is defined as one designed to automatically provide power without delay ortransient during any period when normal power supply is in capable of performing

acceptably.





On line static (solid state) UPS system with sine wave output are required. An off linesystem take about 25 ms for transfer to DC which may impair critical control by

computer system. Normal range of sizes for hydro plant up to 25 MW uninterruptible

power supplies is given below:

Plat size (MW) UPS size (kVA) Remarks

5 - 25 MW 1 – 5 kVA

0.1 to 5 MW 1 or less kVA

Micro Hydel i) Electronic load

controller (ELC) may

use its on converter andconditioned Dc supply

system from UPS orotherwise

ii) If remote controlled

PC may be used with its

own UPS

i) Use power line conditioner

(power supply system)

ii) May use standard single PC UPS





ANNEXURE-II

LIST OF GENERATOR PANEL INDICATION AND RELAYS

Sl.

No.

Designation Inscription Colours

1 L1 DC Supply on Yellow2 L2 AC Supply on Red

3 L3 Generator Circuit Breaker Close Red

4 L4 Generator Circuit Breaker Open Green

5 L5 Generator Circuit Breaker Trip Amber6 L6 Generator Circuit Spring Charge Blue

7 L7 Trip Coil Healthy Yellow

8 L8 DC Supply Failed Red9 L9 Spare Red

10 R R Phase Bus Healthy Red11 Y Y Phase Bus Healthy Yellow

12 B B Phase Bus Healthy Blue

13 IPB Immediate Action Trip Push Button Red14 PB1 Controlled Action Shut Down Push Button Green

15 PB2 Spare Push Button Red

16 TS Temperature Scanner17 DMF Digital Multi Function Meter

18 H Hooter Black

19 ANN Annunciator Black

20 T Test Push Button Black 21 A Accept Push Button Yellow

22 R Reset Push Button

23 BAPB Bell Accepted Push Button24 27 Under Voltage Relay

25 32P Reverse Power Relay

26 51V Voltage Controlled Over Current Relay27 59 Over Voltage Relay

28 60 PT Fuse Failure Relay

29 64S Stator Earth Fault Relay30 46 Negative Phase Sequence Relay



31 40 Loss of Field Relay32 95 Trip coil Supervision relay

33 87G Generator Differential Relay

34 52G Generator Circuit Breaker35 KWTR Kilowatt Transducer

36 BL Electrical Bell37 86G1 Master Trip Relay38 86G2 Master Trip Relay

39 86G3 Master Trip Relay

40 86G4 Master Trip Relay

ANNEXURE-III

LIST OF PROTECTION ELEMENTS IN MICRO PROCESSOR BASED RELAYS

Symbol Description

21 Under Impedance

24 Over Fluxing26 Field Winding Temp

27 Under Voltage

27NT 100% Stator E/F

32 Reverse Power38 Bearing Temp

40 Loss of Field

46 Negative Phase Sequence49 Stator Winding Temp

50BF Breaker Failure50P Instantaneous Phase Over Current

50N Instantaneous Neutral Over Current

50/27 Unintentional Energisation at Stand Still51P Time Delayed Phase Over Current

51N Time Delayed Neutral Over Current

51N Voltage Controlled Over Current59 Over Voltage

59N Residual Over Voltage

64R Restricted E/F

78 Pole Slipping Protection81 Over/ Under Frequency

3.4 gl for monitoring control protection and automation of shp stations

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