dp30b

ExxonMobil Proprietary

ELECTRIC POWER FACILITIES Section Page

POWER GENERATION XXX-B 1 of 52

DESIGN PRACTICES December, 2000

ExxonMobil Research and Engineering Company � Fairfax, VA

CONTENTSSection Page

SCOPE ............................................................................................................................................................4

REFERENCES ................................................................................................................................................4

BACKGROUND ..............................................................................................................................................4

DEFINITIONS ..................................................................................................................................................5

EQUIPMENT TYPES AND APPLICATIONS ..................................................................................................5

TURBINE GENERATORS - GENERAL ..................................................................................................5

STEAM TURBINE GENERATORS .........................................................................................................6

COMBUSTION GAS TURBINE GENERATORS.....................................................................................6

GENERATOR COOLING........................................................................................................................7

GENERATOR EXCITATION AND VOLTAGE REGULATION ................................................................7

NEUTRAL GROUNDING DEVICES .......................................................................................................7

GENERATOR TERMINAL EQUIPMENT ................................................................................................8

SURGE PROTECTION EQUIPMENT.....................................................................................................8

GENERATOR CONTROL AND METERING FACILITIES ......................................................................8

SYNCHRONIZING EQUIPMENT............................................................................................................8

TURBINE GENERATOR AUXILIARIES..................................................................................................9

TURBINE CONDENSERS ......................................................................................................................9

GENERATION AND DISTRIBUTION SWITCHGEAR ..........................................................................10

FEEDER AND CONTROL CIRCUITS...................................................................................................10

SYSTEM DESIGN CONSIDERATIONS ........................................................................................................10

DESIGN BASIS.....................................................................................................................................10

ONE-LINE DIAGRAM ...........................................................................................................................11

LOAD DATA..........................................................................................................................................11

SYSTEM GENERATING CAPACITY....................................................................................................12

SYSTEM VOLTAGE LEVEL AND VOLTAGE PROFILES ....................................................................12

SYSTEM SHORT CIRCUIT LEVELS....................................................................................................12

MAIN BUS ARRANGEMENTS..............................................................................................................13

FEEDER ARRANGEMENTS ................................................................................................................13

SUPPLY TO POWER PLANT AUXILIARIES........................................................................................13

SYSTEM PROTECTION.......................................................................................................................14

SYSTEM AND GENERATOR NEUTRAL GROUNDING ......................................................................14

KILOWATT (REAL POWER) CONTROL ..............................................................................................15

KILOVAR (REACTIVE POWER) CONTROL ........................................................................................16

SYSTEM STABILITY ............................................................................................................................16

MOTOR STARTING AND REACCELERATION ...................................................................................18

LOAD SHEDDING ................................................................................................................................18

Changes shown by ➧


Section Page ELECTRIC POWER FACILITIES

XXX-B 2 of 52 POWER GENERATIONDecember, 2000 DESIGN PRACTICES


CONTENTS (Cont)Section Page

SYSTEM DESIGN PROCEDURES............................................................................................................... 19

COMPONENT DESIGN PROCEDURES ...................................................................................................... 21

TURBINE GENERATOR ...................................................................................................................... 21

TURBINE GENERATOR PROTECTION.............................................................................................. 22

SYSTEM PROTECTION....................................................................................................................... 24

MAIN BUS ............................................................................................................................................ 24

BUS TIE CIRCUITS.............................................................................................................................. 25

FEEDER CIRCUITS ............................................................................................................................. 25

GROUND FAULT PROTECTION ......................................................................................................... 25

GROUNDING DEVICES FOR RESISTANCE GROUNDED SYSTEMS............................................... 26

RESISTORS FOR LOW RESISTANCE GROUNDED SYSTEMS........................................................ 26

RESISTANCE DEVICES FOR HIGH RESISTANCE GROUNDED SYSTEMS .................................... 27

TURBINE GENERATOR AND SYSTEM CONTROL AND METERING ............................................... 28

STATION CONTROL POWER BATTERY AND DISTRIBUTION PANELS.......................................... 30

COMPUTER PROGRAMS............................................................................................................................ 30

APPENDIX A - LOAD SHEDDING CALCULATIONS .................................................................................. 49

RATE OF FREQUENCY DECAY.......................................................................................................... 49

INERTIA CONSTANT - INDIVIDUAL UNIT .......................................................................................... 49

APPENDIX B - REPRESENTATIVE DESIGN SPECIFICATION FOR COMPLEX MULTI-GENERATOREXPANSION ........................................................................................................................ 50

DESIGN BASIS .................................................................................................................................... 50

GENERAL............................................................................................................................................. 50

REQUIRED SYSTEM STUDIES........................................................................................................... 50

REQUIREMENTS FOR STEAM TURBINE GENERATORS AND ASSOCIATED FACILITIES............ 50

ELECTRICAL DISTRIBUTION AND CONTROL FACILITIES .............................................................. 51

POWER PLANT BLOCK CONTROL AND METERING........................................................................ 51

EQUIPMENT, BUILDINGS AND CONSTRUCTION PROCEDURES................................................... 52

LOAD SUMMARY................................................................................................................................. 52

TYPICAL APPENDICES....................................................................................................................... 52






CONTENTS (Cont)Section Page

FIGURESFigure 1 Generator Loading And Stability Curve......................................................................31Figure 2 Condensing Turbine Generator With Controlled Extraction .......................................31Figure 3 Back-Pressure Turbine Generator With Uncontrolled Extraction ...............................33Figure 4 Gas Turbine Generator Performance.........................................................................34Figure 5 Generator Brushless Excitation System.....................................................................35Figure 6 Generator Static Excitation System ...........................................................................36Figure 7 Main Bus Arrangement Initial Step.............................................................................37Figure 8 Main Bus Arrangement First Expansion.....................................................................37Figure 9 Main Bus To Stub Bus - Synchronizing BUS Arrangement - Second Expansion......38Figure 10 Supply To Power Plant Auxiliaries And Process Substations From Two Main Bus

Generating Station .....................................................................................................39Figure 11 Supply To Power Plant Auxiliaries And Process Substations From Stub Busses.....40Figure 12 Supply To Power Plant Auxiliaries From Unit Arranged Generator And Main

Transformer ...............................................................................................................40Figure 13 One-Line Diagram System Protection For Complex Multi-Bus System ....................41Figure 14 One-Line Diagram Generator Protection Contra-Rotating Steam

Turbine Generator......................................................................................................42Figure 15 One-Line Diagram System Protection Complex Multi-Bus System............................44Figure 16 One-Line Diagram System Turbine Generator And System Protection Two

Main Bus System.......................................................................................................45Figure 17 One Line Diagram (Typical) Gas Turbine Generator Package Power Plant ..............46Figure 18 One Line Diagram (Typical) Gas Turbine Generator Auxiliaries Package

Power Plant................................................................................................................47Figure 19 Rate Of Speed - Drop Of Fully Loaded Steam Turbine Generator For Variously

Suddenly Applied Excess Loads................................................................................48

Revision Memo

12/00 This is an update of Section XXX-B. The changes are covered below bysubsection.REFERENCES - Added internet addresses for the referenced documents.DEFINITION - In Reserve Ratio - Added Firm capacity definition.EQUIPMENT TYPES AND APPLICATIONS - In Turbine Generators subsection-replaced "boot strap operation" with " black start capability". In GeneratorExcitation and Voltage Regulation subsection - Added Max/Min excitation limitersrequirements. In Neutral Grounding Devices subsection - Added Voltage rating ofa grounding transformer. In Generator Terminal Equipment subsection - AddedRogowski Coils. In Synchronizing Equipment subsection - Added Using a specificCircuit Breaker. In Feeder and Control Circuits - Clarified cabling method andreferenced IP16-6-1, P14.1.SYSTEM DESIGN CONSIDERATIONS - In One-Line Diagram subsection -Added Transformer impedance. In System Generating Capacity - Clarifiedreserve ratio requirements. In Main Bus Arrangements subsection - Alternativegenerator connection to systems is proposed. In Steady-State Stabilitysubsection - Revised the requirements. In Loss -of-Stability subsection -Additional requirements for Min excitation limiter and Field undervoltage relay arespecified. In Load Shedding subsection - Proposed PLC based scheme tofrequency based schemes.COMPONENT DESIGN PROCEDURES - In Turbine Generator subsection - Therequirement of 200% current for 30 seconds is clarified. In the relay subsections -Added 81 and 60 relays and descriptions. Figures 5, 13, 14, 15, 16 and 17 werechecked / corrected and updated.





SCOPE

This section presents the fundamental design considerations for electric power generation systems. With few exceptions,power generation utilizes either steam turbine generators or gas turbine generators and this section is restricted to these types.Two exceptions are diesel engine generators and flue-gas expander generators.

The most commonly used generation voltages for industrial plants are in the 6 - 15 kV range. Generation voltage in the 3 to 5kV and 400 to 480 volt range are sometimes used for plants with small total installed capacities, for example, 10,000 kVA andbelow. This section is generally applicable to plants in the 6 - 15 kV range and above 10,000 kVA installed capacity. It may beused with modification for plants operating at lower voltages or with lower capacity.

REFERENCES

DESIGN PRACTICES

Section I Design Economics

Section XV Safety in Plant Design

Section XXVI Steam Facilities

INTERNATIONAL PRACTICES

IP 10-7-2 Special Purpose Steam Turbines for Generator Drivers

IP 10-8-1 Combustion Gas Turbines

IP 16-2-1 Power System Design

IP 16-4-1 Grounding and Overvoltage Protection

IP 16-8-1 Instrument Power Supply

IP 16-9-3 Synchronous Generators

IP 16-11-1 Neutral Grounding Resistors

IP 16-12-1 Switchgear, Control Centers and Bus Duct

IP 16-12-2 Control of Secondary-Selective Substations with Automatic Transfer

➧ OTHER REFERENCES

Recommended Practice for Grounding of Industrial and Commercial Power Systems, ANSI / IEEE (Institute of Electrical andElectronics Engineers) Standard 142-1991, (IEEE Green Book)

Recommended Practice for Protection and Coordination of Industrial and Commercial Power Systems, ANSI / IEEE Standard242-1986, (IEEE Buff Book)

IEEE Guide for the Application of Neutral Grounding in Electric Utility Systems, Part 2, Grounding of Synchronous GeneratorSystems, IEEE Standard C62.92, 1989. (Note: IEEE Standards can be ordered online from www.ieee.org)

Dunki-Jacobs, J. R., Transient Stability Criteria of Industrial Power Systems � A Quantitative Analysis, IEEE Conference Paper60-1176. (Reprints available through [email protected])

Computer Representation of Excitation Systems, IEEE Transactions Paper 31 TP67-424, IEEE Committee Report

Fountain, L. L. and Blackburn, J. L., Application and Testing of Frequency Relays for Load Shedding, IEEE (formerly AIEE)Transactions Paper 54-372. (Reprints available through [email protected])

Lokay, H. E. and Bortnyk, V., Application of Under-Frequency Relays for Automatic Load Shedding, IEEE Transactions Paper31 TP67-447. (Paper copy available online at www.geindustrial.com/edc/pm/notes/get6449.pdf)

BACKGROUND

The electric power generation system is part of the overall plant utility system and provides electric power to onsite and offsiteareas as well as to utilization equipment in the power plant itself.

The power generators may be the only source of plant electric power or may operate in conjunction with a public utility supply.In the latter case, the in-plant generation may be operated in synchronism with the public utility supply or separated from thepublic utility supply. In some locations, power in excess of plant requirements is exchanged or sold to the public utility systemin accordance with power contract terms.






DEFINITIONS

(Refer to Section XXX-A and the following.)

Base Load

Setting the output capacity of a turbine generator at a fixed value for long periods of time.

Charging Current

The capacitive current which flows as a result of the inherent phase to ground capacitance of electrical system componentssuch as insulated cables, insulated rotating machine windings, surge capacitors and overhead lines.

Circuit Breaker Position Semaphore

A control board device which is part of a mimic bus and which combines control switch, position indication and statusdisagreement functions. A typical semaphore permits the operator to open and close the circuit breaker, indicates breakeropen or closed by horizontal or vertical position, and flashes when the breaker is tripped or closed.

Rectifier

A device used to convert alternating current (a-c) to direct current (d-c).

➧ Reserve Ratio

Ratio of the installed capacity to the firm capacity of electric power sources. (Firm Capacity means steady state capacity withlargest source out of service).

Stub Bus

A bus connected to a synchronizing bus and having one or more generators or a purchased power source. Stub busses areused to supply plant loads and are sometimes called �machine busses".

Synchronizing Bus

A bus used to transfer power between stub busses or between plants in the case of separate power plants. Used with reactors,in stub bus-synchronizing bus circuits, the synchronizing bus-stub bus arrangement is an effective means of limiting theincrease in system short circuit levels when generation capacity is added to an existing system.

Turbine Generator Capability

The capability of the turbine generator to produce real power (kilowatts or megawatts) and reactive power (kilovars ormegavars). Real power capability is determined by the rating of the steam turbine or gas turbine driver; reactive powercapability by the generator volt-ampere (kVA or MVA) rating and the capability of the generator excitation system.

Unit Concept for Boiler and Turbine Generator

The arrangement in which a boiler is connected to one turbine generator only. Boiler and turbine generator auxiliaries are alsosized and arranged to supply these single units only.

EQUIPMENT TYPES AND APPLICATIONS

TURBINE GENERATORS - GENERAL

The electric power generating units most commonly used in ExxonMobil plants are driven either by steam turbines orcombustion gas-turbines .

Generators are usually two-pole, of non-salient pole construction (3600 rpm 60 Hz or 3000 rpm 50 Hz), with closed circuitcooling systems. Steam turbine driven units manufactured in the U.S.A. are direct driven without speed reduction gears; unitsmanufactured elsewhere may be direct driven or driven through reduction gears. Gas turbine driven units may be direct drivenor driven through reduction gears. Typical generator voltages are 4.16 and 13.2 kV in the Americas; 5 or 6, 10 or 11, and 15kV in Europe and locations following European practice.

Generator excitation systems may be the brushless type having a rotating a-c exciter and rotating rectifier; the static typeemploying a stationary rectifier assembly and no-rotating parts except the generator rotor slip rings; or a combination type usinga rotating a-c exciter, a stationary static rectifier, and generator rotor slip rings.





EQUIPMENT TYPES AND APPLICATIONS (Cont)

Gas turbines for refinery and petrochemical plant turbine generator service are usually the heavy duty industrial type. In otherapplications, such as pipeline service, aircraft type gas turbines are sometimes used.

➧ Gas-turbine generator units can be supplied as self-contained packaged units with an enclosure for the generating equipment,excitation equipment, control and protective relaying equipment. These units require only fuel, water, and the main electricalsystem connections. Package units can also be equipped with Black-Start capability in which the unit automatically restorespower to the electrical system after a total utilities loss.

Each turbine generator will have specific real power (kilowatt or megawatt) and reactive power (kilovar or megavar) capability.Real power capability limit is a function of turbine capability. Reactive power capability is a function of generator and excitationsystem capability.

Figure 1 is a typical generator capability curve showing the real power-reactive power-power factor relationship.

STEAM TURBINE GENERATORS

Steam turbine generators can be classified according to turbine type:

• Condensing • Extraction Condensing

• Non-condensing • Extraction Non-condensing

The condensing unit is the most flexible for power generation purposes. It can generate power over the range from no-loadsteam flow (approximately 10% of rated flow) up to the rated flow capability of the turbine. All throttle flow is exhausted at apressure below atmospheric into a steam condenser and passes back to the boiler deaerator for use as boiler feed water.Therefore, the condensing turbine generator is not affected by process steam load variations and can generate power asrequired by the electrical load. However, because of the large amount of heat remaining in the steam entering the condenser,which must be rejected to the cooling water, straight condensing operation is held to the practical minimum. A typical industrialplant condensing cycle may have a cycle efficiency of 25%. In contrast, a public utility power plant condensing cycle can havean efficiency of 39%. Therefore, when purchased power is available, power generated in industrial condensing generation hasto compete with power generated in the usually much higher efficiency public utility cycle.

The non-condensing unit (also known as a �back-pressure" unit) exhausts steam at an exhaust pressure level aboveatmospheric pressure. These units are usually controlled by a controller which responds to exhaust pressure level changes.Power generation is a function of a steam demand at the exhaust pressure level and can not be adjusted independently.

Extraction units have one or more outlets at intermediate pressure levels between inlet and exhaust pressure levels. Extractionunits may be condensing or non-condensing. The extraction is usually controlled (automatic) responding to steam loadvariations at the extraction pressure level but may be uncontrolled when this type meets the system design basis. In theuncontrolled type, flow from the extraction outlet is dictated by the turbine design alone and system pressure at the extractionlevel must be controlled by other equipment. Power generation capability for the extraction type is basically a function of thesteam load requirement at the extraction pressure level. However, the extraction condensing unit can accept electrical loadvariations without regard to process steam requirements within the kilowatt limits imposed by the proportion of the inlet steamflow that can be sent to the steam condenser. Typical capability curves for extraction units are shown in Figures 2 and 3.

Power generation capability of non-condensing, extraction-condensing, and extraction non-condensing units is affected byseasonal variations in process steam loads. This variation can be substantial and its effect on power generation capabilitymust be determined for each application.

Non-condensing and extraction units improve cycle efficiency over condensing cycle values since all or part of the steam flowto the turbine inlet does not pass to a condenser and is utilized after leaving the turbine. The amount of improvement dependson the specific plant design.

COMBUSTION GAS TURBINE GENERATORS

These units compress air for combustion in the gas turbine compression stage, burn the compressed air-fuel mixture incombustion chambers and expand the hot combustion gases in the power turbine stages to drive the generator (and thecompression stage). The hot exhaust gas is passed to an exhaust stack or into waste heat utilization equipment such as a heatrecovery steam generator (HRSG).

The gas turbine generator has the capability of generating power over its entire range as dictated by electrical load. For unitstypically used in ExxonMobil plants, gas turbine heat rates for operation without utilization of the heat contained in the exhaustgases are in the 12,000 - 14,000 Btu per kilowatt-hour range. The cycle efficiency is in the 27 to 24% range.

Economic design and operation dictate that, when possible, the exhaust heat be utilized and that the gas turbine be operatedas close to rating as possible. Waste heat utilization can improve cycle efficiency into the 50 to 75% range. On the other hand,operation at 50% of rated gas turbine capability can increase the heat rate approximately 30% and decreases the heat contentof the exhaust gas approximately 25%.







Gas turbine capability varies inversely with ambient air temperature. Nameplate rating is normally at International StandardsOrganization (ISO) conditions, 15°C (59°F) and 1 bar (14.696 psia) ambient conditions. Formerly, 80°F was widely used as thenameplate-rating ambient temperature. For each application, the standard conditions rating must be adjusted to reflect the sitemaximum ambient temperature and elevation.

Figure 4 is a typical gas turbine performance curve showing inlet air temperature - exhaust temperature - fuel consumption -output relationships (based on 80°F).

GENERATOR COOLING

Two-pole generators require closed circuit cooling systems, with air or hydrogen as the cooling medium which is passed overthe generator windings. In the United States, vendor practice is to use air as the cooling medium for smaller generators, andhydrogen for larger generators. The size at which hydrogen cooling is used varies among vendors, but is typically above the 75MVA (megavolt ampere) generator size. Air-water and hydrogen-water heat exchangers are normally used although air-finexchangers may be used for specific cases where economics or ambient conditions dictate. Water-cooled exchangers arelocated on the top of the generator or included as part of the generator enclosure. Some gas turbine generator units suppliedwith slow speed (600 - 720 rpm) generators use once-through air cooling systems.

Closed circuit cooling systems should provide at least two independent cooling sections to permit removal of one section whilethe turbine generator is in service at reduced capacity, usually 67% minimum.

GENERATOR EXCITATION AND VOLTAGE REGULATION

The excitation system is comprised of the generator field (rotor winding) and the equipment required to supply d-c to the field.Voltage is generated by the action of the magnetic field established by the generator rotor winding on the conductors of thegenerator stator winding.

The basic types of modern excitation systems are the static and the brushless rotating type. Equipment arrangements vary somanufacturer's information should be consulted. Examples of the types are shown in Figures 5 and 6.

The static type takes a voltage supply and a current supply from the generator leads to external rectification equipment whichreturns d-c to the generator field via the rotor slip ring and brush harness.

The brushless type has a separate a-c generator mounted on the main generator shaft which supplies a-c to a rotating rectifierassembly also mounted on the shaft which supplies d-c to the field.

One variation uses a shaft-mounted a-c generator, external rectifying equipment and rotor slip-rings and brush harness.

The excitation system is controlled by the generator voltage regulator. In the automatic mode, the voltage regulator receives avoltage sensing input and a reactive current compensation input from potential and current transformers, respectivelyconnected to the generator terminal leads. The regulator converts the current to a modifying voltage which adds to or subtractsfrom the input voltage. The resultant voltage is compared to the regulator setting value and the regulator adjusts the excitationsystem to restore the generator voltage to the level equivalent to the regulator setting. The regulator may also be operatedmanually.

The reactive current compensation feature is required to permit generators to operate in synchronism (in parallel) and to controlthe sharing of reactive load requirements.

Power factor regulators are sometimes used in conjunction with the voltage regulator when generators operate in parallel with apublic utility system and close power factor or var (kvar) control is needed. These regulators exert vernier-like action on thegenerator voltage, operating relatively slowly to compensate for small voltage changes. They are switched out automaticallyand the voltage regulator takes over when large changes occur requiring fast regulator action.

➧ Excitation systems may also be provided, if required, with other control accessories such as maximum excitation limiters, linedrop compensators, power system stabilizers, etc. Maximum/Minimum excitation limiters are required when two or moregenerators are operating in parallel, especially if the utility tie connection is weak or island operation is contemplated.

NEUTRAL GROUNDING DEVICES

The most common method of neutral grounding for medium voltage systems is low resistance grounding. A grounding resistoris used to limit the ground fault current to the lowest value which is compatible with the protective relaying. Values normallyfound in ExxonMobil plants range from 400 amperes to 1600 amperes, although one multiple source system had a 4500ampere level at one time.

The resistor ohmic value and current capacity is set by the ground fault current level selected. For instance, a 400 ampereresistor on a 13.8 kV system has a resistance of about 20 ohms. The resistors are usually not provided with taps. Theirthermal rating is a short time rating such as 10 seconds since all ground faults are tripped.






➧ The neutral grounding device used for a high resistance grounded system usually consists of a single phase distribution orsimilar type transformer with a loading resistor on the secondary winding. This provides the effect of the high resistance in theneutral circuit required for this type system. Since faults are not tripped automatically but activate alarms only, fault currentsmust be as low as possible. However, the fault current level must equal or exceed system charging current, or destructiveovervoltages can occur. The voltage rating of a grounding transformer should not be less than the Line-to-Line voltage.

On medium voltage systems, fault current levels in the order of 5 amperes are typical for high-resistance-type grounding. Allequipment must be fully rated since faults are not tripped automatically.

High resistance grounding packages are sometimes available which provide not only the grounding device, but also a controlpackage which can provide a pulse current for fault location purposes. Ground detection either via protective relays or grounddetection ammeters are normally provided.

GENERATOR TERMINAL EQUIPMENT

Normal practice is to provide space in the generator phase and neutral lead terminal compartment or enclosure for current andpotential transformers associated with generator control and protection and for surge equipment. The phase and neutral leadsmay be in common or separate compartments or enclosures depending on manufacturer's design.

➧ A typical arrangement is:

• Phase lead compartment.

+ Partial discharge measuring system ( such as Rogowski coils)

+ Surge protection arresters and capacitors.

+ Current transformer for the voltage regulator.

+ Current transformers for generator differential relays (when generator feeder is not included in the differential zone).

+ Potential transformers for voltage regulator, voltage restraint overcurrent, negative sequence, overvoltage, reversepower and loss of excitation protective functions.

• Neutral lead compartment.

+ Current transformers for voltage restraint overcurrent relay, negative sequence relay, reverse power relay and loss ofexcitation relay.

+ Current transformers for generator differential relay.

SURGE PROTECTION EQUIPMENT

Normal practice provides surge protection equipment consisting of lightning arresters and capacitors for each generator. Thisequipment is provided to protect against any possibility that the generator stator winding will be exposed to lightning orswitching surges. While the initial facilities may make such exposure unlikely, the surge protection package involves smalladditional cost and is best installed with the initial application

Surge protection may also be required at other points in the system in line with normal distribution system practice fortransformers or busses which are exposed to overhead open-wire circuits either directly or indirectly through cable connections.

GENERATOR CONTROL AND METERING FACILITIES

Normal practice is to provide all the generator control and practically all of the metering facilities in the power plant centralcontrol room or the utilities console of the refinery central control room. Metering at the local panel is limited to excitationvoltage and current. In some cases, even these meters have been omitted.

The turbine will require a local panel fully equipped to permit local start-up and run-up of the unit to rated speed. However,when the unit is at or close to rated speed, control is shifted to the control room for synchronizing to the system.

SYNCHRONIZING EQUIPMENT

➧ Turbine generators are synchronized to the electrical system using a specific circuit breaker (or one of available breakers). Thefunction of the synchronizing equipment is provided to insure that, at the closing of the circuit breaker, the voltage difference,the frequency difference (slip frequency) and the phase angle difference between the incoming unit and the system voltage arewithin acceptable limits. Synchronizing equipment may be for either manual or automatic operation.







Equipment for manual operation includes a synchroscope whose rotating pointer measures frequency difference and phaseangle difference, incoming unit and running unit voltmeters and frequency meters, and indicating lights connected across theopen breaker through PT's. The system operator carries out the synchronizing operation with the following controls:

1. The turbine governor motor control switch which varies the turbine speed. This changes the frequency of the generatoroutput voltage and controls the frequency difference and phase angle difference between the generator voltage and theelectrical system voltage.

2. The voltage regulator set point control which, in turn, changes the magnitude of the generator output voltage.

3. The control switch for the circuit breaker across which the synchronizing takes place (usually the circuit breaker connectedto the generator terminals but other breakers can be used). When the synchroscope and the voltmeter indicate thevoltages are in synchronism, the operator uses the control switch to close the circuit breaker.

Automatic synchronizing provisions include the manual equipment plus automatic equipment to carry out the frequency andvoltage control functions and circuit breaker closing. In some cases, the circuit breaker closing action is left to the operator. Anintermediate synchronizing arrangement combines the manual control features with frequency, voltage and phase anglemeasurement equipment which operates to prevent the circuit breaker closing if these conditions are not within acceptablelimits.

Automatic synchronizing equipment must also permit closing the open circuit breaker into a de-energized bus.

TURBINE GENERATOR AUXILIARIES

The auxiliaries are those equipment components and utilities supplies required for start-up and shutdown and for normaloperation. They vary according to the type of turbine generator. Therefore, specific requirements should be established foreach design using data which is representative of the generating equipment which will be used. Following are typicalexamples:

Steam Turbine Generators:

• Lube oil and control oil or fluid systems including reservoirs, coolers and pumps.

• Gland sealing steam condenser.

• Turning gear and motor.

• Cooling water system for lube oil and generator air coolers.

• A-C and D-C supplies for control panels.

• Air ejectors for start-up and normal operation (condensing turbines only).

• Condensate pumps (condensing units only).

Gas Turbine Generators:

• Lube oil and seal oil system including reservoirs, pumps and coolers.

• Cranking motor, steam turbine or engine.

• Turning gear and motor.

• Distillate fuel system.

• Gaseous fuel system including gas compressor (if required).

• Cooling water system for lube oil and generator air coolers.

• A-C power supply for start-up.

TURBINE CONDENSERS

The steam turbine condenser is a steam-water surface condenser connected to the turbine exhaust. The exhaust steam iscooled to the liquid phase, collected in the condenser hotwell and then pumped back into the deaerator stage of the feedwatersystem.

Normal practice is to use a divided shell condenser to permit maintenance of one half while the turbine generator is in operationat reduced output, usually at 67% of rating.






GENERATION AND DISTRIBUTION SWITCHGEAR

This switchgear is the most critical part of the plant electrical system. It is usually the switching and protection center for themajor circuits of the overall plant system.

ExxonMobil normal practice is to use single bus metal clad switchgear with drawout circuit breakers as contrasted to doublebus type having a normal bus and a transfer bus for switching flexibility.

This switchgear usually contains all the protective relaying for generation and distribution circuits. However, generatorprotection has sometimes been located in a separate enclosure at the generator location. This decision is made usually on thebasis of vendor responsibility. This switchgear may also contain excitation system elements.

For most power plant installations, the switchgear is located separately from the turbine generators and from the power plantcontrol room. In these cases, switching of the circuits is always carried out by the control room operator using control switcheslocated on the control room panel; control switches on the switchgear are for maintenance or emergency purposes.

Locations for the generator and distribution switchgear should minimize any possibilities of physical or fire damage. In somecases, a unit concept has been adopted which provides separate rooms for each major switchgear bus and for auxiliaryswitchgear associated with the turbine generator supplying the bus and for the associated boiler if a unit boiler-turbine conceptis used.

FEEDER AND CONTROL CIRCUITS

➧ All of the important feeder and control circuits required for the plant system will usually be located in the power plant. Therouting of circuits between generators, switchgear, and control room and for circuits leaving the plant must be selected tominimize damage possibilities. Unlike process substations, a cable vault is often the best answer for routing and protection(IP16-6-1, P.14.1). The vault should be equipped with smoke detectors and adequate lighting. Circuit routing in the vaults andin other parts of the power plant should provide spacing between dual power and control circuits so that a single incident willnot affect both circuits.

SYSTEM DESIGN CONSIDERATIONS

DESIGN BASIS

During the planning and early design stages, the design basis must be fixed so that the design specification includes allrequirements needed to conform to the basis. Fixing the design basis requires close collaboration with the steam systemdesigner, the electrical distribution system designer and with the Owner.

Expansion or revamp projects which require integration with an existing system place more constraints on the designer'salternatives than do grass roots projects. These constraints must be identified in the early planning design stage, if possible.

The designer must:

1. Identify all planned normal and abnormal operating conditions that the design must cover. This must include Owner'splans for operation of existing units.

2. Determine operational and capacity limitations of specific system design alternatives.

3. Obtain Owner's acceptance of the limitations or agree on required changes.

Following are some of the factors which must be considered:

• How must the new generating units operate on the system, i.e., base loaded, responding to electrical load changes orresponding to steam load changes?

• Will the units act to control pressure of the various steam system levels in the plant or will this be done by existing turbinegenerators, boilers or pressure reducing stations.

• What are the foreseeable load ranges for the new units and what effect will this have on existing units.

• Will the boiler-steam turbine generator use the unit concept. If so, will the generator be connected through a step-up unittransformer to a higher voltage level or will it be connected directly to the power plant main bus having the same voltagelevel as the generator.

• For gas turbine generator units, how will waste heat be utilized, what is the range of waste heat utilization, and how doesthis range effect economics?

• Will the plant generation operate in synchronism with a public utility system?

• What provisions should be made to separate the in-plant system from the public utility when faults occur in the lattersystem?






SYSTEM DESIGN CONSIDERATIONS (Cont)

• What are the effects on the in-plant system when it separates from the utility system and operates independently?Depending on the proportions of the total load supplied by in-plant generation and by the public utility system, theseparation of the two systems can result in substantial changes in the loading of the generator. This, in turn, affects steamload and pressures.

• What are the requirements for pressure reducing system control and boiler control to cope with turbine generator automatictrips and steam system changes when in-plant generation separates from the public utility system?

• What provisions are required for initial startup operations? This requires establishing a tentative start-up sequence.

• What are the requirements for future expansion of the initial installation?

• What motor starting and reacceleration requirements will be imposed on the system and on individual turbine generatorunits?

• Turbine exhaust and extraction steam temperatures increase as load decreases. Start-up operations will dictate that unitsoperate at no load and light loads during initial operation. Turbine extraction and exhaust flow-temperature characteristicsmay not be compatible with downstream piping, flange and equipment limits. The steam system design should includedesuperheating facilities on extraction and exhaust levels unless specific turbine data is available which shows thatdesuperheating is not required.

ONE-LINE DIAGRAM

This diagram together with the system load data are the two most important tools for developing and presenting the systemdesign. The one-line diagram is a graphic representation of all the important components of the electrical system such asgenerators, purchased power transformers, main busses and feeders, load center substations, etc. It also shows the basicprotective relaying schemes.

➧ One line diagrams for design specifications should include all power and excitation circuits, including protective relaying andmetering. The following specific information on components should be included:

Generators Voltage, kW rating, power factor or kvar rating.

Reactances (assumed or actual)

x″d � subtransient reactance

x′d � transient reactance

xd � synchronous reactance

Power Transformers KVA (self cooled / forced cooled), fixed taps or range of automatic on-load tapchangers, winding connections and voltages and impedance.

Circuit Breakers Continuous current rating.

Busses Voltage (all busses), calculated minimum and maximum short-circuit levels(generation and purchased power busses).

Neutral Grounding Devices Resistance or reactance in ohms, taps if provided, and current rating.

Current Transformers Number.

Potential Transformers Number and connection.

Protective Relays Number, ANSI function number, associated auxiliary or lockout relays, dottedlines to show breaker tripped or auxiliary relay activated.

Automatic Transfer Scheme Dotted lines to breakers affected, �N.O.� and �N.C.� to indicate breakers whichare normally open and normally closed.

In the planning stages of a design, the one-line diagram need not have all the details specified above. A diagram showing thearrangement of the power system main busses and feeders and load center substations and the size of major componentssuch as generators, transformers, and feeds is sufficient.

LOAD DATA

The load data lists and summarizes the electrical load on the overall system and on system components. The load data isused to establish the capacity requirements for the various elements of the system. Load data summaries for the plant'snormal and abnormal operating conditions will show which condition is determining. The various operating conditions shouldbe evident from load data provided by process and offsite designers.






The process and offsite designers provide the load data which is the basic input for the electrical system design. These datawill be �normal" operating loads unless there are specific operating conditions which substantially increase or decrease theplant load. In this case, as many sets of input load data are required as there are operating conditions.

Load growth and reserve capacity factors are applied to the input load data during the course of the design to reflect thechanges in the quality of the load data being used. Refer to Section XXX-A, for rules on the application of load growth andreserve capacity factors.

SYSTEM GENERATING CAPACITY

In selecting the number and capacity of turbine generators, normal practice is to provide a reserve ratio of 1.25 minimum forgrass roots installations. Usually this reserve ratio should be in the 1.33 to 1.5 range. For modifications to existing plants,reserve ratio should be based on actual load experience and demonstrated capacity of generating units. A reserve ratio of lessthan 1.0 is not advisable as experience has shown a rapid fall off in stability occurs when this threshold is crossed.

In establishing the capacity of individual generating units, attention must be paid to operating conditions which limit unit output.For non-condensing, non-condensing extraction and extraction condensing units, steam system operating conditions must beexamined to determine their effect on output of a particular unit. Condensing unit capability decreases as condenser coolingwater temperature rises. Extraction or non-condensing unit output may be limited by summer steam loads. Gas turbinegenerator capability must be adjusted to reflect site ambient temperature.

SYSTEM VOLTAGE LEVEL AND VOLTAGE PROFILES

Voltage levels for power generation facilities of the capacities usually found in ExxonMobil plants will be in the 4.16 to 15 kVrange. In North and South America, 4.16 and 13.8 kV are nominal generating voltages most frequently used. In Europe and incountries following European practice, 5 or 6, 10 or 11 and 15 kV are commonly used.

Equipment and wiring costs, continuous current and short circuit current capabilities of available switchgear, and the voltagelevel of the public utility supply influence the selection of the voltage level. Each specific system design requires that a study bemade of the significant economic and technical factors so that the most suitable level is selected.

For plant expansions, the starting point is the existing voltage level. The study must determine whether there is a sound basisfor introducing a new voltage level.

The following preliminary assumptions for grass-roots plants can be made subject to confirmation for the specific design.

Installed CapacityUp to 10 MVA

10 MVA to 20 MVA

Above 20 MVA

U.S.A. Practice4.16 kV

4.16 kV or 13.8 kV

13.8 kV

European Practice6 kV

6 kV, 10 or 11 kV, 15 kV

10 or 11 kV, 15 kV

Installed capacity includes all generating units and public utility supply transformers.

Voltage profiles for the plant system under normal and abnormal operating configurations and for motor starting andreacceleration should be made. These profiles show whether voltage at busses and at utilization equipment terminals arewithin acceptable limits. Adequacy of transformer tap ranges should also be verified. Equipment terminal voltage limits andacceptable system voltage drops are specified in IP 16-2-1, Power System Design.

The PCMagnet or an equivalent program should be used early in the design specification phase to determine the generatortransformer tap range and voltage profile. During the contractor's detailed engineering phase the tap range should beoptimized/fine tuned based on the actual plant/vendor design data.

SYSTEM SHORT CIRCUIT LEVELS

The system short circuit level is determined by the kVA capacity, impedance and number of power sources, i.e., turbinegenerator and purchased power, which operate in parallel.

System short circuit calculations should be made to determine the maximum short circuit level for equipment rating purposesand the minimum short circuit level for motor starting and reacceleration and steady-state conditions. Minimum levels will coverabnormal conditions such as island operation of specific busses if this is an operating condition. The design basis for suchconditions should be carefully assessed to insure that conditions which must be met are realistic. Particular attention must alsobe paid to minimum short circuit levels which result from early operation with less than normal capacity in service. All shortcircuit calculation methods should conform to the methods used for rating the equipment used. This information can beobtained from switchgear manufacturers if it is not known.







All circuit breakers and bus and distribution feeders must be fully rated for the system maximum short circuit level. Themaximum level should include any required provision for planned future capacity. The impact of the future capacity onalternative system designs should be assessed before the final bus and feeder arrangement is selected. This is particularlyimportant where planned future capacity requires a change to higher interrupting capacity switchgear.

When high short circuit levels are present, for instance above 500 MVA at 13.8 kV, design alternatives should be consideredwhich use reactors to reduce the level and permit use of lower interrupting capacity switchgear. For instance, reactors can beused in the stub bus-synchronizing bus connections or in feeders to distribution substations at the generated voltage level.When reactors are considered or applied, their effects on steady-state and motor starting and reaccelerating voltage conditionsand system stability must be assessed for both normal and abnormal operating conditions.

➧ MAIN BUS ARRANGEMENTS

Some commonly used configurations for generator busses in the power plant are shown in Figures 7 - 9. In many cases, theinitial plant will have two main busses connected by a tie breaker which is normally closed. One or two generators areconnected to each bus. As the plant expands, short circuit and continuous current levels increase and use of reactors or asynchronizing bus with tie reactors is necessary to reduce the effect of added generation capacity and to stay within switchgearshort circuit capability. In some cases, the �stub bus - synchronizing bus" concept has been used initially.

All bus arrangements must be checked for operating limitations when a generator or bus is out of service. For instance, motorstarting capability on a stub bus may be severely limited when the connected generator is out of service and all bus load issupplied through the synchronizing bus. It is advisable to have a carefully thought out plan for expanding generation capacityto a level such as twice initial capacity before fixing the main bus arrangement. Adoption of a maximum connected capacitylimit per bus provides system flexibility and avoids excess loss of capacity when a fault occurs. For example, capacityconnected to a main or stub bus may be limited to a 15 to 25 MW range and additional busses added as more capacity isneeded. Direct connection to grid via a generator step up transformer should be considered for a generator capacity in excessof 60 MW. This threshold may vary depending on the grid voltage available.

FEEDER ARRANGEMENTS

When determining the number of main bus feeder circuit breakers required to supply the plant load, the designer should assesscontinuous current capacity of feeder circuit breakers, location of load centers with respect to the power plant, the installed costof feeder circuits and flexibility of the design. The designer must strike a balance which adequately utilizes the capacity of thefeeder circuit breakers and retains sufficient flexibility for maintenance purposes. A 13.8 kV feeder circuit breaker rated 1200amperes can carry 28,600 kVA without exceeding its continuous current rating.

Assuming all loads require dual supplies from the power plant, a suggested starting point is two feeder breakers for processloads, two for power plant and adjacent utilities services and a third pair for offsite and other utilities services. A check shouldbe made of feeder load versus breaker capacity and whether an alternative routing of feeders is more economical even ifadditional circuit breakers are required.

SUPPLY TO POWER PLANT AUXILIARIES

The aim is to provide feeders which are as independent as possible, so that the effect of a single fault is limited to a minimum.Also, the design must be checked to see if it is suitable for the initial start-up and for subsequent start-ups and shutdowns. Thisis particularly critical where no purchased power connection is available and the plant must be �boot strapped" from aconstruction power supply or a small emergency generator. Normally power is first required for plant and instrument air,treated water, cooling water and fuel pump services and for instrument power and lube systems to get the boilers in operation.It is sometimes necessary, where construction power is limited, to make special or temporary provisions for running the largerservices such as boiler fans, feed pumps and cooling water pumps whose drivers may be medium voltage motors. In the caseof gas turbine generators, the start-up problem is somewhat simpler since the unit can be supplied with a starting turbine ordiesel engine and electric power may be needed only for fuel pumps, instrument power supply, and heaters. However, thespecific requirements for each installation should be checked. The designer must review the start-up procedure with the steamsystem and rotating equipment engineers to insure that the system arrangement for the power plant auxiliaries is suitable.

The designer should avoid situations where one or several drivers of auxiliaries needed for power plant operation requiresextensive energizing of distribution facilities outside the power plant block. This is not always possible but the extent should beheld to the practical minimum.

Figures 10 and 11 are the typical feeder arrangements for supply to process substation and power plant auxiliaries.






Where very large turbine generators are unit connected, each through a unit transformer to a higher voltage system, auxiliaryloads may be supplied from the unit auxiliaries' transformer connected at the generator terminals. A start-up supply connectedto the secondary bus supplied by the unit auxiliaries' transformer should be provided. The start up supply may be from asecond unit generator or from an outside source. Figure 12 illustrates this arrangement. Alternatively, two separate feedersfrom outside sources may be used with bus arrangement as shown in Figure 10. Note that, to restore power after a total plantfailure, an independent power source is required.

When an outside source such as purchased power or a supply from a second power house is available, using this source forone of the two sources for auxiliaries will usually provide protection against failures which could shutdown all sources integral toone power plant.

SYSTEM PROTECTION

Within economic limits, the system should be designed so that it can be adequately protected. This means that first-lineprotection is provided to protect the system and its equipment from abnormal conditions including short circuits and that back-up protection is provided for short circuits. The protection should provide prompt removal from service of any system elementwhich has been short circuited, or operates abnormally so as to damage the element, or interfere with effective operation of therest of the system.

Adequate protection also requires that first-line and back-up relaying is sensitive, selective and fast. It must be sufficientlysensitive to operate reliably under minimum fault conditions. It must be selective to distinguish between conditions whichrequire instantaneous operation, time delay operation, or no operation. It must disconnect faulted elements as rapidly aspossible to minimize damage and upset on the system.

First-line and back-up protection for generator, main bus and main bus feeders should aim to clear phase faults, and preferablyground faults, within one second for normal short-circuit level faults. Protection for busses at the same voltage level as thegeneration bus but electrically closer to utilization levels should be faster and operate first for faults in utilization equipment andcircuits.

To meet these fault clearing times, differential and/or pilot wire protection and instantaneous phase and ground overcurrentprotection is usually required for busses and feeders at the generator voltage level.

In systems having three or more busses, series connected at the same voltage level, back-up clearing times above one secondmay have to be accepted. Sometimes, faster clearing times can be obtained by application of directional phase and groundovercurrent relays at tie breakers to isolate parts of the system if first-line protection fails.

Figures 13 - 16 illustrate system and generator protection used in two multiple bus systems and in a dual main bus systeminstalled at three ExxonMobil plants.

SYSTEM AND GENERATOR NEUTRAL GROUNDING

Selection of the neutral grounding method is a critical design choice which must be made early in the design specificationphase.

U.S.A. and ExxonMobil normal practice is to use low resistance grounding for medium voltage systems. In Germany and incountries following German practice, ground fault neutralizers (resonant grounding such as Petersen coils) are used forgrounding the system neutral.

High resistance grounding is another method of neutral grounding. It is used to limit ground fault currents to very low values, toalarm only on ground faults and permit operation to continue without tripping the grounded circuit. The ground fault currentmust not be less than the system three phase charging current. Generally, the use of high resistance grounding in systemswhere the ground fault current will exceed 10 amperes should be avoided. This will generally limit use of this type of groundingto generators connected to the distribution busses through unit transformers, i.e., without distribution circuits at the generatorvoltage level. It also finds use in power plant auxiliaries substations where there is a large incentive to avoid power plantupsets which occur if a circuit supplying a boiler feed pump motor or forced draft fan motor tripped.

The system neutral of the low-resistance grounded system may be grounded at one power source only, even though severalsource neutral points are available. This arrangement has the following characteristics:

• Fault current flow paths are usually less complex and it is easier to limit ground fault magnitudes than in multiple groundedneutral systems. Ground fault current equal to full load current of the largest generator or 400-amperes minimum aretypical values.

• All bus tie breakers must be normally closed. When a tie breaker opens automatically, parts of the system becomeungrounded.

• Directional ground fault relaying which sees across tie breakers plus logic circuitry is required to ensure that all faultconditions will be cleared even if ground fault current flow ceases when a bus tie breaker is tripped.







• To avoid ungrounded operation of part of the system, it is necessary to provide logic or control circuits to permit switchingthe system neutral ground to a second source if the normal source trips or the system splits into independent islands afterspecific fault conditions.

• Neutral switching equipment, either circuit breakers (preferred) or load-break switches are required for the neutral of eachgenerator having its neutral grounded. When drawout circuit breakers are used, it is possible to provide as few as twodrawout elements. One is for the generator which is grounded; the second, for the generator which will be grounded if thefirst is tripped. The neutral switching equipment should have provisions for remote tripping and closing from the controlroom and by the required logic circuits.

Multiple grounded neutral sources may have advantages for particular situations such as those involving multiple stub bus-synchronizing bus arrangements. It should be noted that multiple grounded sources will usually mean higher ground faultcurrents than single neutral point grounding. Also, particular attention must be paid to ground fault current paths to insure thatprotective relaying maintains selectivity under all operating conditions and fault locations, particularly when the system is splitinto islands.

Where multiple system grounded sources are used, ground fault current levels should not, in general, exceed the 1200 to 1600ampere range. Above these levels, the benefits associated with resistance grounding are reduced. Where a system hasundergone several expansions or modifications such as adding purchased power connections, it may not be practical to staywithin the range mentioned. In this case, 2400 amperes is the next maximum limit recommended although at least onetechnical reference puts 4000 amperes as the outside maximum limit.

Where complex generation systems are involved, such as those involving separate powerhouses each with multiple units ormultiple bus systems, special studies must be made of system grounding alternatives including the use of groundingtransformers, so that the best method can be selected. These studies should cover all planned system operating conditionsand determine the levels of ground fault current which results for ground faults occurring on the various busses and feeders.These studies should confirm that first-line and back-up protection is provided for all conditions.

KILOWATT (REAL POWER) CONTROL

The turbine governor controls the kilowatt or real power output of the turbine generator. The governor acts on the steamturbine inlet valves or on the gas turbine fuel valve to change the unit's power output.

Steam turbines may operate on speed control (all turbine types) or on pressure control (non-condensing and extractioncondensing turbine types).

Speed control has two modes available - isochronous control and speed / load or droop control. Speed / load control isnormally used.

The isochronous mode restores the unit to the pre-set value after a load change. Isochronous control of one unit can be usedto maintain system frequency in plants which operate independent of a public utility system and where close frequency controlis important. The unit on isochronous control must have sufficient range to absorb all load changes. This limits the mode tocondensing units or gas-turbine units.

Speed / load or droop control utilizes the governor's negative max/min droop characteristics. That is, unit speed drops with anincrease in load and rises with a decrease in load. For instance, with a 5% negative droop or speed regulation, the unit speedwill decrease 5% between no load and full load. Governor adjustments permit different reference speed settings so that theturbine speed can be set between 100 to 105% of rated speed at no load. With 5% droop this results in 95% to 100% speed atfull load. Normally, the reference setting is selected so the unit is at rated speed at normal operating load.

When two or more units operate in synchronism on speed / load control, and are not synchronized to a public utility system,load changes cause a change in both units' speed and system frequency. If the two units have the same reference max/mindroop setting and are the same rating, the load change is shared equally. Different size units will share in the same proportionas their ratings if the same reference setting is used. With different reference settings, a plot of the settings on a speed versusload basis is necessary to determine how load changes will be shared. Since a change in load will cause a change in systemfrequency, the system must be returned to normal frequency when the change occurs.

When units operate synchronized with a public utility system, the public utility fixes the frequency. Electrical load changeswithout a corresponding increase or decrease of steam to the turbine inlet or fuel to the gas turbine are reflected as changes inpower supplied by the public utility.

Pressure control for non-condensing and extraction turbines provides a signal from the pressure sensor to the inlet and/orextraction valves to cause a change in inlet steam flow and a resultant output change. This causes a shifting of electrical loadbetween paralleled units.






KILOVAR (REACTIVE POWER) CONTROL

Generator kilovar output and, therefore its power factor, is controlled by action of the voltage regulator that changes the fieldcurrent (excitation level) and thus the generator terminal voltage.

When a single isolated unit is supplying the load, the load's power factor fixes the kilovar output. When more than one unitoperate in synchronism to supply the load, or when one unit operates in synchronism with a public utility system, reactive powerproduction can be shared between the sources within the limits set by each unit's kvar capability. The sharing is controlled bythe droop setting of the voltage regulator. Reactive droop compensation is normally used. It creates a droop in generatorvoltage proportional to the reactive current and equivalent to that which would be produced by inserting a reactor betweengenerator terminals and the paralleling point. This droop is required for stability of operation and prevents paralleled units fromtransferring reactive circulating current from one unit to another through action of the individual voltage regulators. In general,satisfactory sharing of reactive load will be obtained if there is from four to six percent reactive voltage drop between paralleledunits.

SYSTEM STABILITY (References contain additional information on stability in industrial plants.)

General - Stability can be defined as the capability of the electrical system to develop restoring forces between its elementswhich are equal to or greater that the disturbing forces so as to restore equilibrium between the elements of the system. Thesystem needs this capability for both steady-state and transient conditions. Stability can also be defined as the tendency of thepower system and its components to remain in synchronism or �in step"; instability is a loss of synchronism or �falling out ofstep".

➧ Steady-State Stability - Steady-state stability refers to the ability of the system to transfer power free from sudden change inMVAR/Voltage and frequency /MW for gradual application of real and reactive load. The steady-state limit is the maximumpower level that can be transferred. Steady-state stability is hardly ever a problem in properly designed industrial systems.Satisfactory steady-state voltage levels throughout the system are usually indicative of systems which will be stable in thesteady state.

Transient Stability - Transient stability for the industrial system means that, during and after sudden disturbances, generatorsand synchronous motors remain in synchronism and induction motors do not stall. The sudden disturbance can be a suddenapplication of load. However, most often in the industrial system, it is a fault or a combination of the fault and its subsequentisolation by tripping part of the system.

Fault Effect on Transient Stability - Transient stability is affected by the type, location and duration of the fault. Three phasefaults electrically close to the generator terminals have the most severe effect on transient stability since the voltage at the faultpoint is zero on all phases. There can be no synchronizing power flow past the fault point between the paralleled generators tohold or pull the units back into synchronism. In addition, the power flow from the generator is cut to zero and all the mechanicalenergy input to the turbine is transformed into rotational energy and accelerates the turbine and generator rotor system.

In the case of phase-to-phase, phase-to-phase-to-ground, and single-phase-to-ground faults, not all phase voltages go to zero.There is some synchronizing power flow and less mechanical energy input is converted to rotor acceleration and the overalleffect on stability is less severe than for the three-phase fault.

Fault clearing time has an important effect on the ability of the system to keep rotating equipment in stable operation. Theresults of studies on industrial systems have shown that, in general, systems proved to be stable if 3 phase faults on strategiccircuits are cleared instantaneously or within 0.25 seconds.

Stability and Power Angle Value - When system stability studies are made, one rule of thumb is that the system will be stableif the power angle between the generator voltages behind the transient reactance of paralleled units does not:

1. Exceed 90 degrees during fault clearing, and

2. Exceed 140 - 160 degrees during the recovery swings after fault clearing.

In less rigorous calculations, the synchronizing power flow between paralleled units is taken to be directly proportional to thesine of the power angle.

Conditions Promoting Instability - Conditions which increase possibilities of instability during and after fault clearing are:

• Different inertia constants, (H), for paralleled generator-driver units, i.e., one unit's H = 2kW�sec/kVA, another at 4, a thirdat 10.

• Generators paralleled through high reactance synchronizing ties and/or with a large (�weak") public utility system.

• Absence of differential or instantaneous relays on circuits which are electrically close to the generator.







Conditions Promoting Stability - Conditions which increase the possibilities of remaining stable during and after fault clearingare the inverse of conditions stated in the previous paragraph.

• Inertia constants which are the same or do not differ widely.

• Low reactance synchronizing ties and no public utility tie.

• Differential or instantaneous relays on circuits which are electrically close to the generator.

Effects of Loss-of-Stability - The effects of loss-of-stability are detrimental to the system:

• If generators are left operating out-of-step with the remainder of the system and field applied, their stator windings can bedamaged due to high mechanical and thermal stresses caused by high oscillating currents. In some cases, these currentsmay even exceed three-phase fault current levels.

➧ Loss-of-Stability Caused by Loss-of-Excitation - If a loss-of-excitation relay (Device 40) is not provided or it malfunctions, anindividual generator may fall out of synchronism with the system in five to ten seconds after its excitation is lost, at full load. InExxonMobil designs, loss-of-excitation relays provide first-line protection for this condition, but back-up protection is usually notprovided.

Loss-of-excitation relays can be accidentally tripped by AVR/exciter action, if a parallel generator fails to ceiling (maximum)excitation. A minimum excitation limiter on the exciter controls can prevent unwanted tripping of the 'good' machine, whilewaiting for the failed machine to trip on overcurrent. It is recommended to use Field undervoltage relays as backup on lightlyloaded salient pole machines as they may not pull out of step during loss-of-excitation but would draw excessive reactive powerVARs.

Protection Application for Stability - As stated previously, the provision of differential or instantaneous overcurrent trippingon strategic circuits promotes stability.

Stability study results provide the maximum permissible fault clearing time limits for the various types of faults. First lineprotection must provide clearing times which are within these limits. It is very desirable that back-up protection clearing timesfor all fault types also be within the stability limits. However, when this cannot be done, the minimum should be that back-upprotection clearing times for phase to ground faults are within the limits indicated for stability. Phase-to-ground faults are by farthe majority of faults experienced in ExxonMobil and other industrial plant systems which use similar design and equipmentapplication practices.

Usually, meeting the first-line and minimum back-up protection requirements stated does not present a problem for grass rootsinstallations or for the new system facilities added to existing systems. However, it may not be possible to adapt protectionsystems on existing facilities to the new conditions resulting from the expansion. The remedy is to add out-of-step protection totrip particular generating units or parts of the system when loss-of-stability occurs. This requires careful assessment andOwner's understanding and agreement.

Out-of-step protection was assessed during expansion of two ExxonMobil installations. The protection to be applied consistedof an angle impedance relay (General Electric type CEX 17E or equal) with an auxiliary relay (Type NAA 19B or equal). Thisrelay requires two current transformers and one potential transformer connected line-to-line or several connected delta-delta.In one case, the protection was installed. In the second, the decision was not to install since clearing times for the first-lineprotection for all fault types and the back-up protection for phase-to-ground faults were within maximum limits for stability.

Computer Programs for Stability Studies - Computer Program 3317 can be used for checks of system stability forsteady-state and transient conditions. The steady-state condition has been covered in SYSTEM VOLTAGE LEVELS ANDPROFILES. The transient conditions are checked by plots of generator terminal voltage and phase angle during and after faultclearing as part of short circuit calculations. This check should be done for systems having any of the conditions promotinginstability mentioned earlier. This check should be made early in the design specification stage using typical constants wherespecific data is not available. Final runs should be made in the detailed engineering phase as soon as machine and systemdata is available. Other programs available for stability studies are PSS/E from Power Technologies, Inc. and I*SIM from SKMSystem Analysis, Inc.

These computer programs require data for modeling the turbine generator units. Early collection of the data for existing units isrequired to permit preliminary runs to be made early in the design specification stage. Typical data may be used for new unitsand as a last resort for existing units. It is also possible to do manual calculations of a simplified two-machine system toprovide an indication of stability conditions. This requires that units lumped together to form a two machine model haveapproximately the same inertia constants. Manual calculations should be verified by later computer calculations.






MOTOR STARTING AND REACCELERATION

For the industrial plant system, the other important measurement of system transient performance is the ability of the system tostart single large motors and reaccelerate this motor and groups of smaller motors when voltage is restored after a systemvoltage loss or disturbance. These abnormal voltage conditions may be caused by short circuits either in the plant system or inthe public utility system, or by the loss of a generating unit or utility tie line.

For the starting of a single large motor, the motor must have torque capability, at the reduced voltage caused by starting inrushcurrent, to meet the load torque requirement of the driven equipment plus an additional torque margin, 5% percent minimum atany speed, to provide the torque necessary to accelerate the motor and driven equipment. This requirement applies untilnormal operating speed is reached.

During voltage losses or disturbances, running induction motors will have their torque output reduced due to low voltageconditions. The driven equipment torque requirement exerts a decelerating effect causing an increase in motor slip and adecrease in operating speed.

When voltage is restored to the motor terminals, the corresponding motor torque must be sufficient to meet the load torquerequirement at that instant and have the additional torque margin to provide the torque necessary for acceleration until normaloperating speed is reached.

If the restored voltage is not high enough to provide this torque requirement, the motor will not accelerate and either remain atone speed or continue to slow down until tripped by the motor protective devices. By 90 percent of rated speed and lower, thetypical motor draws currents near the starting current level.

One of the most common situations requiring reacceleration of motors in ExxonMobil plants is the automatic transfer of asecondary selection substation. When voltage is restored to the de-energized bus by the transfer operation, all critical motorssupplied from the bus must reaccelerate. Further, the voltage drop caused by the reacceleration must not be large enough toupset running motors.

Computer Program 3317 can be used to determine power generation system capability for motor starting and reacceleration. Ifthe system supplies a single large motor whose rating is approximately 25% or greater of minimum generator operating kVA,preliminary computer runs should be carried out early in the design specification stage. The run should check adequacy of thegeneration and excitation capacity and of motor torque characteristics. The large motor and associated driven equipmentshould be fully simulated. At this stage, it is usually necessary to use typical rather than specific generator and excitationcharacteristics and motor and driven equipment speed-torque curves and rotor inertia values.

If computer runs are made at this stage for the large motor check, system reacceleration capability can also be checked. Sincedefinitive data is usually not available on smaller motors, which are not fully simulated, simplified system representation andgrouped motor loads can be used to set up preliminary reacceleration steps.

The design criteria normally used for successful reacceleration is that the initial voltage at the motor bus should not be less that80% of the bus rated voltage. This will ensure that voltage at motor terminals is at least 75% of motor nameplate voltage,which is sufficient for reaccelerating of normal inertia loads, such as pumps, when motors have at least 100% starting and200% maximum torque.

The designer should determine if any loads, other than the fully simulated devices, are likely to be high inertia loads. Fans andblowers are likely candidates. For busses serving such loads it is advisable to maintain the bus voltage at the 85% level and toflag these services for specific checks during the detailed engineering phase.

Check that the power plant auxiliaries do not trip during a system disturbance and result in a power plant shutdown. To avoiddropout of the starters during a voltage dip for critical auxiliary loads, consider using latching contactors in place of the normallyused magnetically held contactors.

Computer checks are advisable at the early design specification stage for expansions of complex systems even when no largemotors are involved. Final computer runs for starting and reacceleration should be made as soon as possible in the detailedengineering phase when definitive generator and excitation system data and critical motor data are available.

LOAD SHEDDING

Provisions for load shedding are required to protect the electrical system and the generation equipment from continuousoverload conditions which are high enough to slow the generation units, thereby causing a drop in system frequency. Thiscondition may arise when there is a sudden loss of a generating unit or a public utility supply circuit. Turbine generators cannotoperate continuously at reduced frequency without exceeding permissible mechanical stresses. The manufacturer will specifythe minimum permissible reduced frequency for continuous operation.

A typical permitted minimum frequency value for industrial units is 57 Hz or 5% reduction for a 12.5 MW 60 Hz condensingsteam generator. This permits an overload condition up to 11% above maximum capacity if the ratio of load decrease tofrequency decrease is 2 to 1. Figure 19 shows the effect of various overloads on frequency decay.







For grass roots installations with normal ratios of firm capacity to maximum demand, load shedding covers the condition whereall reserve is in operation and additional capacity is lost. Load shedding is the economical way to provide process andelectrical system and equipment protection against double and higher contingency loss-of-capacity conditions which do notjustify installing additional reserve. A double contingency condition in a 3 unit or 4 unit system results in a 100% (3 unit) or 50%(4 unit) overload at maximum load conditions.

The extent of load shedding to be provided requires a careful analysis of all system operating conditions, required maintenanceschedules for generation units and the effects of forced outages. Also loads must be graded so that lowest priority loads canbe assigned to the first load shedding steps. This has to be done in the detailed engineering phase of the project in thecontractor's office, but the designer should provide as detailed a set of requirements as possible within his schedule limits. Asa minimum, the load shedding design philosophy must be stated.

Load shedding provisions in their simplest form consist of underfrequency relays, timers and auxiliary relays arranged to shedload in one or more steps by tripping strategic circuit breakers to reduce load. More complex and flexible systems may includemicroprocessor based systems which can be readily adjusted as operating conditions change.

Some design criteria for load shedding systems are:

• Highest frequency setting and fastest timing must permit transient oscillations due to system power swings withoutinitiating load shedding. Underfrequency relays may have a built-in initial delay to offset transient effects. One example isthe Westinghouse KF relay which has a built-in 6 cycle minimum delay.

• The fewer the load shedding steps, the larger the increment of load to be shed to correct a given condition. However,fewer steps probably mean faster restoration to normal conditions.

• Where multiple underfrequency relays are installed, the relays with the highest and fastest setting should be the mostelectrically remote from the busses which experience the highest angular changes during transients such as synchronizingpower transfers.

• Some small loads, such as motor operated valves, ventilating fans, etc., may be critical to plant operations or may berequired during emergency conditions. Overall system design and load shedding system designs should recognize theseloads and make provisions for them.

➧ The designer has two methods available which show the need to check for load shedding on multi-unit systems where the needmay not be obvious. These methods are (1) check of settle-out frequency and (2) check of initial rate of frequency decay. Thesettle-out frequency has to be no lower than the turbine generator manufacturer's specified minimum limit for continuousoperation. Initial rates of frequency decay on systems for which load shedding has been provided are 2.5 Hz/sec, 1.5 Hz/secand 1 Hz/sec. Where shedding large amounts of load is contemplated, frequency based schemes can be difficult to apply. Insuch a case, a Programmable Logic based scheme is preferred.

Calculation procedures for settle-out frequency, rate of frequency decay and time-to-reach a specific frequency are included inthe APPENDIX.

SYSTEM DESIGN PROCEDURES

The procedures for developing the system design are:

Step 1 - Gather system data and background information for developing the design. A major part of these data is obtainedduring the engineering survey. These data and information should include:

• One-line diagrams of any existing power supply and distribution facilities including maximum and minimum short circuitlevels and system protective relaying.

• Number, capacity and characteristics of all existing generators and their excitation system characteristics.

• Capacity and characteristics of new generators and their excitation system characteristics. These data can be obtainedfrom equipment vendors or from data available for existing similar units.

• Operating configurations for existing generators and public utility supplies. This includes number of generators inoperation for all normal and abnormal cases, whether tie breakers are normally open or closed, operation of generators insynchronism with utility system or not, etc.

• Public utility reclosure practice on supply circuits to the plant, including number of reclosures and delay time before eachreclosure.

• Public utility voltage regulation on a daily, weekly and seasonal basis as applicable.

• Normal and maximum electric power loads for existing facilities and for new onsite and offsite facilities and resultant 15-minute and 8-hour demands.





SYSTEM DESIGN PROCEDURES (Cont)

• Owner design preferences.

• Maintenance schedules for existing generation and public utility supplies.

• Frequency and duration of public utility power supply outages expected at supply point to the plant. Information shouldinclude outage data for single supply circuits and total power outage data. Make sure data covers all elements of thepublic utility system which affect reliability of the supply circuits to the plant such as voltage dips.

• Estimated cost of typical power outage and undesirable operational effects.

• Public utility rate structure including standby capacity demand and energy charges, and any capital contribution or ratestructure provision required to provide the required number of circuits and voltage level.

• Availability of public utility generation and distribution capacity to supply the required load without restrictions, plus anyutility load shedding provisions and requirements.

Step 2 - Where public utility supplies are available, planning stage decisions are required on the following:

• Is the public utility supply reliable?

• Is purchased power the economical choice over in-plant power generation?

The first question can be answered by analysis of the public utility power outage data. Generally, power supply outageincidence of once per year or longer is considered a reliable supply. An outage rate in the two to five per year range isprobably acceptable if outage duration is in the one second to one minute range. More frequent or longer duration outages areindicative of a lower reliability supply and in-plant generation may be justified on a reliability basis alone.

Justification of in-plant generation as the economical choice requires a multi-disciplinary study which compares purchasedpower to inplant generation alone and to purchased power-generation combinations. The generation study which is usuallycarried out as part of the design basis memorandum (DBM) phase may be part of an overall power-generation / driver studywhich determines whether major drivers will be steam turbines, electric motors or gas turbines (where applicable); whetherpower generation will use steam turbines, gas turbines or a combination of these types, turbine inlet, extraction and exhauststeam conditions, fuel balance / impact on emissions; extent of gas turbine waste heat utilization; the preliminary number andapproximate size of turbine generators, and the generator voltage level.

To carry out the power generation / driver study, normal load demand and maximum demands must be computed from the loaddata collected for existing and new onsite and offsite loads.

Select the number and size of turbine generators so that the reserve ratio (capacity / demand) is in the 1.25 to 1.33 range as aminimum.

Prepare preliminary one-line diagrams of the electrical system configurations to be compared and make the first selection ofvoltage levels. These diagrams should show all equipment components which affect the study economics.

Calculate short circuit levels for each generation and system configuration and select the required switchgear continuous andinterrupting capacity.

Size all system components such as power transformers, current limiting reactors and power distribution cables which affectstudy economics.

Prepare equipment lists for each case which together with the preliminary one-line diagrams will permit investment costs to bedetermined. Equipment lists should, insofar as possible, contain a reference to applicable pages of Cost Engineering Practicesor Investment Curves for each equipment item in the list together with any modifications or qualification to the Cost Engineeringdata.

The investment and operating cost for each case and an analysis of the return on additional investment over the base case(usually purchased power) will determine whether in-plant generation is justified.

The in-plant generation case which is selected from the power generation / driver study provides the starting point for the powergeneration system design.

Step 3 - Update the load data and determine the new firm generation capacity requirement.

Select the number of turbine generators to be installed using vendor data for unit size and capability characteristics. Do notoverlook system operating conditions or other utility conditions which may reduce unit capability.

Confirm the selection of the voltage level used in the planning design.






SYSTEM DESIGN PROCEDURES (Cont)

Make the required system calculations by computer or manually, whichever is applicable. The following calculations arenormally required.

• Load flow for steady-state voltage conditions. This also provides a check of transformer tap setting range. Do notoverlook the effect of voltage variations of the public utility tie.

• System maximum and minimum short circuit levels using latest generator characteristic data. All system operatingconditions must be covered, with particular attention to stepwise project completions which may result in substantiallyreduced short circuit levels in the first stages.

• Motor starting capability for large motors.

• Initial stability check runs for complex systems or those having the conditions tending to instability.

Step 4 - Select first-line and back-up protection for generator and system phase faults using the results of the systemcalculations as a basis. Check protection adequacy using typical relay types at minimum short circuit levels and for alloperating configurations.

Select the system neutral grounding method and size the neutral grounding device after analyzing the alternative systemgrounding methods.

Select first-line and back-up ground fault relay protection and check adequacy of protection for all system operatingconfigurations.

Step 5 - Prepare the system one-line diagrams and design specification. The Appendix contains an outline and synopsis ofcontents for a representative design specification.

COMPONENT DESIGN PROCEDURES

TURBINE GENERATOR

The following International Practices contain the requirements for the turbine and generator components:

IP 10-7-2 - Special Purpose Steam Turbines

IP 10-8-1 - Combustion Gas Turbines

IP 16-9-3 - Synchronous Generators

Each International Practice indicates those requirements for which a decision must be made or additional information provided.Also, the specific power plant design basis may necessitate modifications in areas such as controls, protective devices andinstrumentation.

➧ The generator International Practice includes the requirements for the excitation and voltage regulation system includingrequirements for abnormal current capability of the generator and excitation system under automatic voltage regulator control.These requirements are:

• Maintain 350 percent of generator rated current for a minimum of 2 seconds for any type of short circuit at the generator'sterminals.

• Maintain 200 percent of generator rated current for a minimum of 30 seconds to a load consisting of starting orreaccelerating motors having an average power factor of 20% lagging.

These requirements are specified to insure (1) that the short circuit current decrement characteristic will be such that systemprotection using conventional protective relaying is satisfactory, and (2) that the generator-excitation system capacity (inproportion to the generator's size) and the voltage regulation system's characteristics are adequate to ensure a reasonably�stiff" system for motor starting purposes.

Generating units whose characteristics depart markedly from these requirements are not well suited for application in thetypical ExxonMobil plant system. Although multiple units are installed, the system can have operating conditions requiringisolated unit operation (�island" operation). The requirement of 200% current for 30 seconds exceeds related IEC and IEEEspecifications and may require an oversized exciter. The need for this IP requirement should be considered carefully beforespecifying it. Note that the IP quoted above does not specify the terminal voltage that must be produced under theseconditions, but it must be assumed that the voltage needs to be sufficient to prevent motors from stalling and contactors fromdropping out (generally more than 75%).





COMPONENT DESIGN PROCEDURES (Cont)

TURBINE GENERATOR PROTECTION

Turbine generator protection can be divided into the following categories:

• Protective devices which protect the generator and the turbine against fault conditions internal to the turbine generator orpermit emergency shutdown by the operator. These devices trip the steam turbine throttle / stop valve or gas turbine fuelvalve, the generator circuit breaker and remove excitation. Tripping functions are essentially simultaneous.

• Protective devices which protect the generator against external fault conditions. In a strict sense these fault conditionsrequire only tripping of the generator and removal of the excitation. However, the manufacturer's recommended practicemay be to trip the turbine whenever the generator breaker is to be tripped in order to limit turbine exposure to a potentialoverspeed condition when load is suddenly removed. In these cases, the trip signal is sent first to the turbine throttle/stopvalve or fuel valve and a limit switch or similar device on the valve functions to trip the generator breaker and removeexcitation.

• Protective devices which alarm only. These devices protect against conditions which are potentially harmful but which maybe corrected by proper operator action.

The following listing of protective devices covers each category and includes the device designation and its protective function.The protective devices listed are based on ExxonMobil designs and ANSI / IEEE Standard 242-1986. It may be desirable thatprotection for turbine generators added in expansions of existing plants conform to existing practice at the plant unless thereare good technical reasons to differ. An asterisk in the following paragraphs indicates the protection designated should beprovided on all units.

Devices protecting against internal faults:

87G* - Generator differential relay protecting against faults in the generator stator winding alone or stator winding andconnection to the generator breaker depending on location of the line side current transformers. (When these currenttransformers are located at the generator phase terminals, it is necessary to provide directional phase and ground overcurrentrelays at the generator breaker to protect against faults in the connecting circuit.)

The differential relay protects against phase and ground faults. Sensitivity of ground fault protection is dependent onmagnitude of ground fault current and sensitivity of the relay setting. If more than 15 percent approximately of the statorwinding (closest to neutral point) is unprotected, a sensitive ground differential relay should be added. (The G in the devicenumber 87G above and in the figures in the Appendix, denotes generator. Where both phase and ground differential relays areprovided, the phase differential relays are denoted as (87) and the ground differential relays as (87G)).

40* - Loss of field relay protects the generator against total or partial loss of excitation. Such a loss can result in loss ofsynchronism of the affected machine and may cause other connected machines to become unstable due to low systemvoltage. These conditions occur in about 5 to 10 seconds after a total field loss. While the relay can provide an alarm beforetripping, only losses of field due to operating errors are usually correctable by operator action so this relay is usually arrangedto trip.

Emergency Shutdown Switch* - Pushbutton switches located on the main and local control boards to permit shutdown by theoperator.

Turbine Protection* - Sensors for protection against conditions such as overspeed, low bearing oil pressure, high bearingtemperature, low control oil pressure, high exhaust temperature, excessive vibration, excessive thrust bearing clearance, etc.

A typical tripping arrangement is to have the 87G and 40 devices energize a high speed hand reset lockout relay, device 86,which acts to trip the generator breaker, remove excitation and trip the turbine throttle / stop valve or fuel valve simultaneously.

The emergency shutdown switches and turbine protective devices act to trip the turbine throttle / stop valve or fuel valve directlyand limit switch on the valve acts to energize the 86 device to trip the breaker and remove excitation.

Devices protecting the turbine generator against external faults:

32 - Anti-motoring relay protects the generator and turbine against reverse flow of power into the generator from the system.This condition can appear if there is low or loss of steam flow to the steam turbine (or low or loss of fuel pressure or flow to agas turbine) without a generator breaker trip. In gas turbine applications, this relay is required and is often used to trip thegenerator breaker on normal shutdowns. When the generator drives the gas turbine, the power required to motor the turbineand compressor is 80 to 100 percent of the generator rating so the overall effect on the system is similar to the loss of twogenerators.

The anti-motoring relay is normally not required for steam turbine installations. The steam turbine normally has turbinetemperature indicating and alarm equipment with provision for automatic shutdown to prevent turbine damage if the generatormotors the turbine. Also, the power required to motor the steam turbine is relatively small compared to the gas turbine.







46 - Negative phase sequence relay protects the generator rotor from damage due to thermal heating caused by unbalancedcurrent in the stator. The unbalanced currents induce 120 cycle currents which flow at the rotor surface and in non-magneticwedges and retaining rings. The most likely cause of this condition in ExxonMobil systems is an unbalanced external fault inthe system. Although not required on all units, this relay has generally been included in the protection.

49 - Thermal relay used to monitor stator winding temperature. This relay is normally not provided, but where the generator isequipped with resistance temperature detectors (RTD), they may be used in a bridge circuit to provide input data to the thermalrelay.

51G - Time overcurrent relay which provides backup ground fault protection. Refer to the Ground Fault Protection discussion inthe following section on Resistors for Low Resistance Grounded Systems for additional design features.

51V* - Overcurrent relay with voltage restraint which provides back-up protection for faults external to the generator. It protectsthe generator and system from prolonged short circuit contribution to external faults which have not been cleared by first-lineprotection. The voltage restraint feature prevents relay operations under an ordinary overload condition when voltage is normalbut permits operation as the voltage drops during a fault, thus permitting fast clearing at relatively low fault currents.

When the current transformers supplying this relay are located on the neutral side of the generator windings (preferredlocation), this relay backs up the differential protection of a wye-connected generator if the generator operates alone or withcircuit breaker open such as when running prior to synchronizing.

Separate overcurrent and voltage relays have been used in a voltage control arrangement to provide the 51V back-up function,but this is a much less preferable alternative and should be avoided.

The 51V relay can be used with timing relays to open a bus tie breaker in the first step and in the second step to clear the busto which the generator is connected if fault current continues after the tie is open.

59 - Overvoltage relay protects against overvoltage condition which may result if the potential transformer supplying the voltageregulator blows a fuse and the regulator does not have self-protecting feature. This relay is not normally provided unlessrequired by the turbine generator manufacturer. If applied, the potential transformer supplying the relay should be a differentpotential transformer than the one supplying the voltage regulator, otherwise, the blown fuse causes the regulator to drivetoward maximum while the relay sees no voltage. A voltage balance relay (device 60) may be used in place of an overvoltagerelay where required.

67 - Directional phase overcurrent relay provides first-line protection for phase faults in the generator feeder and back-upprotection for generator internal phase faults. The relay operates on currents flowing from the bus towards the generator.

This relay is not used when the generator differential (87G) zone includes the connection from the generator terminals to thecircuit breaker.

67N - Directional ground overcurrent relay provides first-line protection for generator feeder ground faults and back-upprotection for generator internal ground faults. Note that because of the directional aspect, this protection does not function ifthe generator is operating with its neutral point grounded through the neutral resistor and is the only grounded source. Thisrelay may not be necessary when the 87G zone includes the generator circuit breaker connection.

A typical tripping arrangement is to have the 32, 46, 51V (or timer), 67 and 67N devices energize a second lockout relay,device 86, which trips the generator circuit breaker and removes excitation. Where the turbine manufacturer will not permitopening the generator breaker without closing the turbine throttle / stop or fuel valve, the signal from the 86 relays is sent first tothe throttle / stop or fuel valve, and a limit switch on the valve trips the generator breaker and removes excitation.

Devices which alarm only:

64F* - Field ground detection relay (or system) which monitors the generator field (rotor) circuit for ground faults.

81 - Frequency relay is a device which functions on a predetermined values of frequency - either under or over or on normalsystem frequency or rate of change of frequency.

Winding Temperature Detector* - monitors the temperature of each phase of the generator stator winding. Includes anindicating meter normally located in the control room or may be tied into the Control Center computer.

Moisture or Leak Detector - monitors air-water cooler for moisture which indicates a leak in the cooler.

60 - PT Fuse Failure - This is a voltage balance relay which operates on a given difference in voltage between two circuits.






Excitation Rectifier Diode Fuse Detector - when brushless excitation system rectifying diodes are protected by fuses, adetector is required to detect blown fuses. This is a special stroboscopic light which is used to detect the fuse target pin. Notethat some equipment manufacturers may not provide fuses for these diodes maintaining that the fuses are less reliable than thediodes.

In addition to the protective relays and devices for trip or alarm, there are usually block or bypass functions by particular relaysor devices. These functions should be specified on the one-line diagrams or in the design specification.

Figures 14 and 16 show turbine generator protective relaying for specific steam turbine installations and Figure 17 for a gasturbine installation, respectively. The 60G relay shown in Figure 14 is particular to the specific type of turbine generator (radialflow contra-rotating turbine driving two half size generators) and is not required for the more conventional axial flow turbinegenerator set.

SYSTEM PROTECTION

Selecting the proper protective relaying for the power plant system is much more complex than selecting the generator unitprotection. It is not practical to use a standard relaying system for all plant systems. The protective relaying used must beselected for the specific plant system and for all of the system's normal and abnormal operating configurations. It must alsoprovide clearing times which are compatible with the critical clearing times required for transient stability of the specific plant.

The designer, therefore, must analyze these conditions and select the first-line and back-up protective relaying to provideadequate system and equipment protection. As stated previously, first-line protection must cover all abnormal conditionsincluding short circuits; back-up protection is provided for short circuits only.

In applying first-line and back-up protection, the designer should note that differential and pilot wire type protection provide first-line protection only for the specific zone (bus, feeder or equipment zone) covered by the relay. Separate back-up relaying mustbe provided and is usually provided by time-overcurrent phase and ground relays which will �see" the fault and operate if thereis a first-line protection failure or circuit breaker trip failure. Back-up protection for first-line phase and ground time-overcurrentrelaying is provided by the first-line overcurrent relays on the next circuit breaker closer to the power source. That is, if first-lineprotection fails to clear the faulted element, the phase or ground fault protection on the next circuit breaker closer to the powersource also sees the fault and trips. Therefore, separate back-up relays are not needed. Back-up protection tripping times willbe slower than first-line protection and circuits without faults may be included in the segment of the system which is tripped.

Selection of the first-line and back-up ground fault protection can be more difficult than selecting phase fault protection. Groundfault protection is affected by conditions affecting phase fault protection and, in addition, is affected by the system neutralgrounding method. Ground fault protection analysis should be included as part of the analysis made to select the neutralgrounding method.

The information which follows lists specific relay application for main busses, and main bus tie and main bus feeders. It isintended to provide guidelines based on practices which have been used for specific ExxonMobil plant designs. They areapplicable to reasonably complex multi-unit systems at 13.8 kV or 15 kV. They would not necessarily be applicable to small,lower voltage systems.

The protection for the main busses, main bus tie and main bus feeder circuits should provide instantaneous or nearlyinstantaneous first-line fault protection for phase and ground faults. Back-up protection should preferably provide fault clearingtimes of about one second maximum for main bus faults.

To meet these criteria, the following protective relays are normally used:

MAIN BUS

87 - Differential relay for phase and ground fault protection. Operates to trip all circuit breakers connected to the bus.Protection zones for bus sections overlap at bus tie breakers.

67, 67N - Directional phase and ground overcurrent fault protection. Provided on each bus having a power source when themain bus is operated with normally closed tie breaker. Closed tie is the normal practice. These relays sense current flowacross the tie breaker into a faulted bus or into an uncleared feeder fault. They act as back-up to bus differential and to feederfirst-line protection. They act to isolate the faulted bus or feeder by tripping all breakers connected to the bus. Depending onfault current flow paths, these relays may be arranged for two-stage tripping. The first stage acts to trip specific tie circuits inorder to partially isolate the faulted part of the system; the second stage, trips all circuit breakers connected to the bus if thefault current flow persists.







BUS TIE CIRCUITS

These are the circuits which connect busses having power sources (generator or public utility transformer) and which are notpart of the same switchgear lineup. Protection is provided as follows:

67, 67N - Directional phase and ground fault protection which can act as described under �Main Bus." If the tie circuit isprovided with differential or pilot wire protection, the directionals act as back-up protection for the tie circuit. If fault current canflow in either direction in the tie circuit, directional protection looking in both directions is required.

87, 87P - Differential or pilot wire (87P) provides first-line protection for the tie circuit itself. Use of this type protection isdictated when very fast tripping times are needed to maintain system stability or to permit faster tripping elsewhere in thesystem than permitted by directional protection alone. This latter feature is possible since 87, 87P type protection operatesonly for faults in the bus tie circuit zone and does not have to be selective for faults outside this zone. Therefore the bus tiezone has first-line protection without requiring a step on the time-selectivity ladder.

Pilot wire type protection uses a relay at each end of the circuit rather than a single differential relay and should be consideredas an alternative to differential relaying and used in its place if the circuits exceed a hundred meters in length. Supplementaryrelays are available if desired to continuously check on pilot wire condition and to alarm if pilot wires become short-circuited oropen-circuited.

FEEDER CIRCUITS

These are circuits which either terminate at transformers or at distribution busses at the same voltage level as the powersource busses.

Protection for circuits supplying transformers:

51/50, 50G - Phase overcurrent relays with time and instantaneous tripping elements and zero-sequence type instantaneousground overcurrent relay. If the transformer is 5000 kVA or larger, transformer differential protection should be provided and itszone should include the feeder circuit. This protection becomes the first-line feeder protection. The phase and groundovercurrent relays are retained for back-up protection.

Protection for main bus feeder circuits supplying distribution busses at the generation voltage level will be affected by thesystem configuration back to the power sources and whether feeder circuits from the distribution bus terminate at transformersor another distribution bus. Phase or ground overcurrent protection which are two levels upstream of a circuit havinginstantaneous tripping may have minimum clearing times of 0.8 seconds. Transient stability critical times may requireapplication of bus and feeder differential protection to get faster clearing times without sacrificing selectivity.

GROUND FAULT PROTECTION

Following are some additional design features which must be considered in applying ground fault protection.

When a low resistance grounded system which operates with only one power source grounded is split into independent islandsby ground relay trip of a tie breaker, some islands will then be operating without a system neutral ground. If a ground source isavailable in the island, logic circuits should be specified to automatically switch in the available ground source.

If the ground fault occurs on a part of system which becomes an island without a grounded source, logic circuits should bespecified to insure that the tripping required to clear the fault is completed even though ground fault current flow stopped whenthe system part became an island. This is to prevent continued operation of the island with an uncleared ground fault present.

A ground fault relay, device 51G, in the neutral resistor circuit is used as the final stage of ground fault protection. Its back-upfunction is to operate when all other ground protection has failed. However, operation of the 51G relay should be consideredas a �last ditch" measure and its effect should be as limited as possible. It should trip only the circuits which are connected tothe bus having the faulted circuit. Operation of part of the system without a neutral ground may have to be accepted in thiscase. In some designs, this relay function has been considered critical enough to require two relays whose contacts arearranged so that false operation of one relay will not cause tripping.

If the system design basis is that island operation is required, operation and multiple sources grounded or available forgrounding will probably be required. Ground fault protection must be designed for operation over the full range of ground faultcurrent which can flow under normal and abnormal system configurations.

Figures 13 and 15 show two examples of system protection for multiple bus systems; Figure 16 for a two-bus system.






GROUNDING DEVICES FOR RESISTANCE GROUNDED SYSTEMS

The following is a synopsis of information from the Institute of Electrical and Electronic Engineers Standard 142-1991,Recommended Practice for Grounding Industrial and Commercial Power Systems. The information pertains to systemsgrounded by resistance inserted in the generator neutral circuit.

A system properly grounded by resistance is not subject to destructive transient overvoltages - that is voltages higher than250% of normal line-to-neutral voltage. For resistance grounded systems operating at 15kV and below, serious overvoltageswill not occur unless the value of the resistance in the neutral grounding circuit is outside specified resistance-reactanceparameters.

Following are the definitions, the resistance limits and the usual range of grounded fault currents for low resistance and highresistance grounded systems.

• Resistance grounded (usually called low-resistance grounded) - intentional insertion of resistance into the system neutralso that:

Ro ≥ 2 Xo

Where Ro is the zero sequence resistance of the system and Xo is the zero sequence reactance of the system (includingthe Ro and Xo of the neutral resistance). Usual fault current range is from 25 amperes to several thousand amperes.Ground faults are tripped instantaneously or selectively.

• High resistance grounded - the insertion of nearly the highest permissible resistance into the neutral grounding connectionso that:

Ro ≤ 3

Xco

Where Ro is the zero sequence reactance of the system including the neutral resistance and Xco is the total zero sequencecapacitive reactance of the system.

Available ground fault current is usually limited to 10 amperes maximum and must be at least equal to the total systemcapacitive to ground charging current.

Ground fault protection is arranged for detection and alarm. Therefore, the system has the advantage of permitting thefaulted circuit to remain in operation.

Use of this type system is avoided if the ground fault current exceeds 10 amperes; 5 amperes is a preferred upper limit.

Systems may also be grounded by use of grounding transformers, with or without resistance and by use of ground faultneutralizers. IEEE Standards 142 and C62.92 (References) provide information on the applications.

RESISTORS FOR LOW RESISTANCE GROUNDED SYSTEMS

Selecting the Ground Fault Level - In this system when the ground fault current is small compared to the three phase faultcurrent, the current passing through the resistor is approximately equal to:

I (amperes) = V (system line-to-neutral) / R (resistor ohms)

ExxonMobil practice is to limit the ground fault currents to as low a value as possible but higher than either:

• Fifteen (15) times the lowest reliable operating current of the least sensitive feeder ground relay.

• Five (5) times the lowest reliable operating current of bus ground relaying.

The lowest reliable operating current is assumed to be 1.5 times the relay pickup current values for most relays. For staticrelays, the lowest reliable operating current can be as low as 1.2 times the relay pickup current value.

A good starting point for determining the resistor value is to size the resistor so that ground fault current equals full load currentof the largest generator and then check against the criteria listed above. Usually, the resistor is sized within the limits of aminimum fault current of 400 amperes and a maximum current not exceeding 1200 to 1600 amperes with all grounded sourcesin service.

Resistor Rating - The resistor voltage rating is the system line-to-neutral voltage. The resistor thermal rating is specified interms of the minimum time for which system ground fault current can be carried by the resistor without exceeding its ratedtemperature rise. ExxonMobil practices specify a minimum time value of the larger of:

• 5 times the operating time of the slowest ground fault relay at a fault current level of 80 percent of resistor rated current.

• 10 seconds.







Another Resistance - Reactance Parameter - There is another parameter for the resistance-reactance relationship whichmay be encountered in engineering the system. It is covered here so that the designer has the available background. Thisparameter is:

20X

XandX2R

1

ooo ≤≥ (where X1 is the positive sequence reactance of the system)

Note this parameter includes the additional condition that the Xo/X1 ratio of the system not exceed 20. This additional conditionis not specified in IEEE 142, and it is not likely to need consideration for low-resistance systems grounded through a resistoralone. However, the need to meet this condition was raised during engineering of one ExxonMobil power plant expansion inwhich the expanded system was grounded via a grounding transformer-resistor combination. In this case, the systemcharacteristics were checked and found to meet both conditions.

The reactance and resistance values for both the grounding transformer and resistor are critical, and specific values obtainedfrom manufacturers should be used when checking the parameter. If the parameter is not met, an increase in groundingtransformer size is usually required. If this involves more than nominal cost, further consideration should be given to risksinvolved if the Xo/X1 condition is not met. Also, a check can be made with national standards making groups to determine thelatest thinking with respect to this reactance criteria. There is some controversy over the need to meet the additional condition.

RESISTANCE DEVICES FOR HIGH RESISTANCE GROUNDED SYSTEMS

Ground Fault Current Level Limitations - The effectiveness of the high resistance system in limiting the transient overvoltageis a function of the ability of the neutral resistance to absorb the energy which is stored in the system capacitance to ground atthe instant the ground fault occurs.

The system ground fault current level must be at least equal to the system capacitive charging current from system elementscapacitively coupled to ground. These elements are cables, overhead lines, transformers and rotating machine windings, surgeprotection capacitors and power factor correction capacitors. In the usual industrial system, cable, capacitors and rotatingmachine windings are the most important components. The fault current should be limited to 10 amperes maximum, but 5amperes is a preferred upper limit.

The resistance device is, therefore, sized so that its kilowatt rating is equal to or greater than the total available systemcapacitive-to-ground charging energy in kilovolt amperes.

High-Resistance Grounding Application - Considering the practical implications of the conditions stated, the high resistancesystem is limited to those applications where either:

• There are few or no distribution or utilization circuits at the generation voltage level as in the case of generator-unittransformer installations.

• The capacitively-coupled elements are sufficiently limited so that ground fault current meets the 10 ampere maximum bothfor the initial installation and for reasonable future expansion. Power plant auxiliary substations and some processsubstations are examples.

The criteria specified are easier to meet in systems below 600 volts than in higher voltage systems because (1) capacitivecharging currents are lower at low voltage, and (2) systems are generally limited in size.

High Resistance Grounding Devices and Ratings - The usual practice for providing the high-resistance grounding device forthe generator or transformer neutral in 4 to 15kV systems is to use a single-phase distribution or control transformer with asecondary resistor. The primary of this transformer is connected between the neutral point and ground and the resistor isconnected across the secondary. The fault detection relay is usually a voltage relay but an overcurrent relay may be used.

The voltage rating of the distribution or control transformer primary is the phase-to-phase voltage of the system even thoughthe voltage across the primary during ground faults is the system phase-to-neutral voltage. This is done to decrease thetransformer magnetizing inrush current when the ground fault occurs. In a 13.8 kV system, the primary would be rated 13.8 kV,and the secondary might be 480, 240 or 120 volts.






The transformer and resistor must be continuously rated since, when a ground fault occurs, the faulted circuit's protectivedevice is not tripped and the fault remains on until the circuit is removed from operation by plant personnel.

The effective resistance in the system neutral circuit of the resistor connected across the transformer secondary is the resistorohm value multiplied by the square of the transformer turns ratio:

22

secondaryVoltage

primaryVoltage)Secondary(R

secondaryN

primaryN)yR(Secondar)R(Neutral

−

−=

−

−=

where: N = Number of turns

The resistor ohm value and fault current level value relationship must be such that:

I2 R ≥ I2 Xc

where: I = fault current w charging current to groundR = effective neutral resistor ohmsXc = total system capacitive reactance to ground

The grounding device for systems below 600 volts will normally be a resistor connected directly in the neutral circuit. Additionalinformation on high-resistance grounding of low-voltage systems is covered in Section XXX-C.

TURBINE GENERATOR AND SYSTEM CONTROL AND METERING

Usually, the electrical system control philosophy is that control and operation of the turbine generator and main switchgearcircuit breakers is carried out from a central control room. This includes synchronizing and loading of the units, and trippingand closing of main bus circuit breakers. Additional operations such as switching of auxiliary and distribution substationswitchgear may also be included in accordance with the design basis. The central control room also contains boiler or gasturbine controls and other utilities controls.

The only operations carried out at the turbine generator location are start-up and shutdown. Since circuit switching requiresoperator knowledge of overall electrical system conditions, switching at the switchgear location is done in emergencies only.

The control and operation of the turbine and generator and the electrical system main busses is usually performed from thecentral control room. The older designs have electrical system panels containing all control switches, indicating lights,annunciators, synchronizing equipment, metering, etc. The panels also contain a mimic bus that includes the control switches,position indication and meters for the more important system elements.

Metering philosophy is similar. Local meters at the generator location are limited to whatever is recommended by the turbinegenerator manufacturer for start-up and shutdown. In many cases no meters are required. As a maximum, meters to indicategenerator excitation voltage and field current may be required. All other system and turbine generator meters are located onthe central control panels.

Following is a listing of representative control, metering and relaying locations:

OnSwitchgear

InControl Room

Breaker Control

Synchronizing

Breaker Open-Close Indication

Voltage Meters

Other Meters

Exceptions

Feeder Ammeters

Directional Wattmeter

Protective Relaying

Excitation - Voltmeter

- Ammeter

X

X

X

X

X

X

X

X

X

X

X

X

X

X

X







Representative metering requirements for each generating unit to amplify the listing for the control panel:

• Voltmeter and switch for stator voltage, voltmeter for excitation.

• Ammeters for stator and excitation currents.

• Wattmeter (recording).

• Vector meter (power factor lines imposed on generator capability curve to give instantaneous indication of unit kW, kvarand pf) or kW and kvar indicating meters and power factor meter.

• Frequency Recorder or Indicator.

Microprocessor Based Control System - Current GTG control system designs use a microprocessor based system. Aconsole is provided which contains control and metering for the turbine generator. The mimic and control panels are replacedby a color graphic operator interface station (CRT). Where multiple generating units and a complex system are involved, aseparate utilities console may be provided.

Following are representative design specification requirements for the controls of a recent GTG installation. These sectionsprovide an overview of the control equipment architecture and control and operating objectives. It is intended only to aid thereader in understanding the control system philosophy. It is not a complete description of the control system operation ordesign objectives.

The facilities will be started up / shutdown from a new Local Instrument Shelter (LIS) to be constructed near the GTG andHRSG equipment. Steady state control and monitoring as well as emergency remote trip of the equipment will be from theexisting Operator Console located in the Control Center. The LIS will contain the operator interface panels and controlequipment, as well as a �view only" CRT.

The LIS will be the primary location for startup of the GTG and HRSG equipment. Steady state monitoring will be performedfrom the Control Center Operator Console after the GTG/HRSG is started up.

The LIS will house all Vendor provided control panels, a Contractor provided Auxiliary Instrument / Alarm Panel and a �viewonly" terminal linked to the existing refinery control computer to facilitate startup. The LIS will also include radio and telephonecommunications equipment to insure effective communications between the LIS and the Control Center Operator Console.

The overall objective is to normally run the GTG/HRSG base loaded, i.e., to produce maximum steam with full supplementaryfiring of the HRSG and to generate maximum electric power.

Startup - Startup of the GTG will be accomplished from the Generator Control Panel (microprocessor based data acquisitionand display system) the Exciter Panel (analog control system) and the GE SPEEDTRONIC Mark IV (Mark IV) Control Panel(microprocessor based system) all supplied by the GTG Vendor.

The Mark IV Controller will execute the GT startup functions from commands entered via the process operator's interface.Mark IV will bring the turbine from crank to the full operating speed / no load (FSNL) condition.

After achieving FSNL, generator synchronization and tie-in to the utility bus will be accomplished by the operator from theGenerator Panel via synchronizing controls. The GTG will be brought to minimum load (approximately 2 MW) at this point.(The generator panel CRT will display generator related information such as MW and MVARS generated.) The GTG will thenbe placed in the Base mode from the Mark IV which will cause the GTG to ramp to a maximum MW generation rate.

The operator will then manually adjust the MVARS set point from the Exciter Panel to match the reactive power actuallyconsumed. At this point ( from the Exciter Panel in the LIS), the MVAR loop will be switched to the Cascade mode, allowing theMVARS generated to automatically balance with MVARS consumed.

A 4 - 20 mA signal representing MVARS consumed will be sent from a transducer located in the main substation to the ExciterPanel A/M station. MW consumed, MW generated and MVARS generated transducers shall also be connected to the LIS forinput to the refinery control computer.

Control Transfer to the Control Center - The normal steady state operating mode will be BASE with Remote MW Set Point(maximum electrical power generation with turbine exhaust at high temperature constraint) and Remote MVAR bias for reactivepower generated. The REMOTE SET POINT / MEGAWATT CONTROL mode will be enabled at the Mark IV interface allowingthe Console Operator to enter a Remote MW set point from the computer display.

The operator will then (via an auto / manual station on the Exciter Panel) transfer the MVAR set point bias from local to remote,thus allowing the Console Operator to enter the desired MVAR set point bias from the computer display. (Power factor canalso be the controlling exciter set point.)






Steady State - At steady state, the Mark IV and Exciter Panel will provide all necessary gas turbine and generator control andprotection functions.

The Mark IV will be in Base / Remote MW and will control the turbine fuel gas valve to maximize MW generation (limited byexhaust temperature). The Console Operator will have the capability to enter a Remote MW set point from the computerdisplay to the MARK IV. The operator shall be able to enter a NOx bias signal at the Mark IV Panel (LIS) only. (Remote NOxbias capability from the Control Center can also be provided.)

Turbine Trip - For many cogeneration installations, a generator trip or HRSG trip will cause the shutdown of the gas turbine.At recent ExxonMobil installations the shutdown system has been modified so that only a trip caused by imminent mechanicalfailure (mechanical vibration, low lube oil or liquid in fuel gas) will result in a turbine shutdown. This philosophy eliminatesunnecessary shutdowns and improves the GTG train mechanical life and steam system reliability.

The combined GTG/HRSG controls shall be set up for full load rejection without tripping the turbine. If the generator breakertrips open for a failure external to the GTG skid, the Mark IV will control the speed by reducing the firing and keep the GT on-line. With supplemental firing, steam generation will be possible thereby reducing the impact of the trip on the steam system.

The HRSG will be designed to run dry but at reduced GT exhaust temperature. An HRSG trip due to low drum level willautomatically initiate Runback Control, via a contact from the BMS system to Mark IV. The Mark IV logic will open inlet guidevanes and reduce turbine firing to cool down the exhaust temperature to an acceptable level. This leaves the GTG on-line at areduced power output, reduces thermal shock to the gas turbine (compared to a full trip) and permits GTG loading to resumeimmediately after the HRSG is ready for operation.

In steady state it shall be possible to perform a manual emergency trip of the GTG from the LIS (via the Mark IV panel) or fromthe Console (via a manually operated trip switch input to Mark IV).

The Mark IV shall also incorporate the standard automatic trip functions.

STATION CONTROL POWER BATTERY AND DISTRIBUTION PANELS

The station control battery and associated d-c distribution panels and circuits are critical parts of the plant electrical protectionand control systems. IP 16-2-1, Par. 8, Switchgear Control Power, contains pertinent design requirements which can be usedas a basis for power plant requirements.

Loads supplied from the station battery should be limited to electrical system protection, control and alarm services.Emergency lighting and other loads should have separate supply provisions.

The selection between the lead-acid and nickel-cadmium batteries is based on economics and Owner preference.

For plants using the unit boiler turbine generator arrangement, serious consideration should be given to providing a separatecontrol power battery, battery changer and d-c distribution panels for each turbine generator unit. The unit battery and panelthen supply all control, protection and alarm requirements for main bus, auxiliaries switchgear, etc., associated with the oneturbine generator.

In supplying control power to main bus switchgear and control panels, the following circuits are recommended:

• One circuit to each generator breaker.

• One circuit for feeder breakers of each main bus section.

• One circuit for bus tie breakers.

• Sufficient circuits to central control panel so loss of a circuit affects only one generator or one main bus section.

One circuit to each generator local panel, if required.

D-C instrumentation and control for boilers and turbines are supplied from d-c systems provided expressly for that purpose.Even if the steam system d-c control voltage is the same as the electrical system d-c control voltage, separate batteries, batterychargers, distribution panels, etc., are provided for each system.

COMPUTER PROGRAMS

(Refer to Section XXX-A, for information on applicable computer programs.)






FIGURE 1GENERATOR LOADING AND STABILITY CURVE

4

6

8

10

120.95 0.9

0.850.8

0.7

0.6

0.4

0.2

0.2

0.4

0.6

0.7

0.8

0.850.9 0.95 MW

Turbine Limit

Power Factor

MVAR

Leading Lagging

2 4 6 8 10 122468

RotorCurrent

Limit

Theore

tical S

tabili

ty L

imit

DP30Bf01(Courtesy C. A. Parsons Ltd.)





FIGURE 2CONDENSING TURBINE GENERATOR WITH CONTROLLED EXTRACTION

2.4

2.2

2.0

1.8

1.6

1.4

1.2

1.0

0.8

0.6

0.4

0.2

0

0 20 40 60 80 100

Load KW (Percent Max.)

Th

rott

le F

low

Uni

ts

100% Load

1.6 Units Extraction FlowPlus Cooling Steam

NormalOperation

Operating StraightCondensing With Extr.

Valve Gear LockedWide Open

ZERO

0.2

0.4

0.6

0.8

1.2

1.4

1.6

1.8

1.0 Unit Extraction

Additional OperatingRange Available withOversized High PressureSection

Extraction Factorx 0.2 Unit Extr.

Extr. = 0.4 UnitsZero Extr. = 0.6 Units 1.0 Units

Additional OperatingRange Available withOversized ExhaustSection

Pressure Rise at 100%Load

Max

. R

ated

Loa

d

DP30Bf02

Max

. Exh

aust

Flo

w

Max ThrottleFlow

Total ExtractionAt 80% Load

Max. Throttle FlowAt 80% Load

Performance WithOversized Exhaust

Section

Pressure Rise At80% Load

(Courtesy ofGeneral Electric Co..)






FIGURE 3BACK-PRESSURE TURBINE GENERATOR WITH UNCONTROLLED EXTRACTION

RatedExtraction

Flow

Zero ExtractionFlow

Output

Load KW (Percent Maximum Capability)

Th

rott

le F

low

� U

nits

0 25 50 75 100

2.0

1.5

1.0

0.5

DP30Bf03

(Courtesy of Stal LavalAB)





FIGURE 4GAS TURBINE GENERATOR PERFORMANCE

0 20 40 60 80 100 110 120

538

482

427

371

316

260

204

149

110

100

90

80

70

60

50

40

30

Generator Output � Percent

Fuel C

onsu

mptio

n P

erc

ent

Turb

ine E

xhaust

Tem

pera

ture

� °

C

43°C 27°C 4°C � 18°C

Air Flow

� 9

0%

100%

108%

116%

Compressor InletTemperature

� 18°C LoadLimit

46°C LoadLimit

27°C LoadLimit

43°C LoadLimit

DP30Bf04(Courtesy of General Electric Co.)






FIGURE 5GENERATOR BRUSHLESS EXCITATION SYSTEM

PMG = Permanent Magnet GeneratorRCT = Reactive Current (Parallel)

Compensation TransformerR = Resistor, Rheostat

SP = Surge SuppressorVAR = Voltage Adjusting Rheostat

41 = Field SwitchEF = Exciter Field

Voltage Regulator

UnderFrequencyAdjustment

VoltageRange

Adjustment

StabilityAdjustment

Reactive CurrentCompensation

Adjustment

R R R R

E1

E2

E3

F+

F�

Sensing

Voltage

D-CField

Output

VoltageAdjustment

A-CPowerInput

SensingCurrent

VAR

41

41

PMG

3-P

hase

Sensi

ng

Re

qu

ire

dfo

r

PM

AC

Exciter

RotatingDiode

Assembly

Generator

GeneratorField

SP

RCT

AlternatePosition for

RCT

ToLoadE

F

FieldContactor

+ -

Battery

ACAUX.

LAN Connection toTurbine Control Panel(Coax or Fibre Optic)

DP30Bf05





FIGURE 6GENERATOR STATIC EXCITATION SYSTEM

D-CVoltageRegulator

FieldFlashingCircuit

StationBattery

FieldBreaker

ControlCurrent

Generator

ToNeutral

Grounding

LinearReactor

PPTSCT's

CT

ToLoad

PT's

A-CVoltageRegulator

RectifierIsolationSwitches

PowerRectifierBridges

CT = Current TransformerPT = Potential TransformerPPT = Power Potential TransformerSCT = Saturable Current Transformers

DP30Bf06

(Courtesy of General Electric Co.)






FIGURE 7MAIN BUS ARRANGEMENT INITIAL STEP

GG

N.C.

Feeders Feeders

DP30Bf07

FIGURE 8MAIN BUS ARRANGEMENT FIRST EXPANSION

G GGG15 MW to 25 MWMaximum Per Bus

Section

N.C.

Feeders Feeders

DP30Bf08





FIGURE 9MAIN BUS TO STUB BUS - SYNCHRONIZING BUS

ARRANGEMENT - SECOND EXPANSION

Synchronizing Bus

G G G G G G

N.C. N.C. N.C.

Stub Bus Stub Bus Stub Bus

Feeders Feeders Feeders

N.C.

Reactor

Stub Bus

Feeders

N.C. = Normally Closed

PublicUtility

Connection

DP30Bf09






FIGURE 10SUPPLY TO POWER PLANT AUXILIARIES AND

PROCESS SUBSTATIONS FROM TWO MAIN BUS GENERATING STATION

Generation Busses

Power Plant ServicesMedium Voltage

StartupPower Supply

Low Voltage

Power PlantCommon Services

Boiler +Turbine "A"Services

Boiler +Turbine "B"Services

StandbyGenerator

EssentialServicesSwitchgear

(IP 16-8-1)

G

MM

Low Voltage

Process Plant SubStation � Medium Voltage

DP30Bf10





FIGURE 11SUPPLY TO POWER PLANT AUXILIARIES

AND PROCESS SUBSTATIONS FROM STUB BUSSES

GG

Stub Bus Stub Bus

ProcessSubstationNo.1

Boiler"A"MediumAnd LowVoltageLoads

PowerPlantCommonServices

ProcessSubstationNo.1

Boiler"B"MediumAnd LowVoltageLoads

PowerPlantCommonServices

DP30Bf11

FIGURE 12SUPPLY TO POWER PLANT AUXILIARIES

FROM UNIT ARRANGED GENERATOR AND MAIN TRANSFORMER

High VoltageBus

MainTransformer

AuxiliariesTransformer

Unit 1

G

AlternativeTo

StartupSupply

Unit 1Auxiliaries

Unit 2Auxiliaries

G

Unit 2

High VoltageBus

DP30Bf12






➧ FIGURE 13ONE-LINE DIAGRAM SYSTEM PROTECTION FOR COMPLEX MULTI-BUS SYSTEM

LE

GE

ND

Re

sid

ua

l Vo

ltag

e R

ela

y

Un

de

rvo

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Inst

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Gro

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Tim

e O

ver

Cu

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nt

With

Inst

an

tan

eo

us

Att

ach

me

nt

Tim

e O

verc

urr

en

t

Tim

e O

verc

urr

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t,G

rou

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Fa

ult

Pre

ssu

re R

ela

y

Dir

ect

ion

al O

verc

urr

en

t

Dir

ect

ion

al O

verc

urr

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t,G

rou

nd

Dir

ect

ion

al O

verc

urr

en

t,w

ithV

olta

ge

Re

stra

int

Un

de

r F

req

ue

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Re

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for

Lo

ad

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din

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nd

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set

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Fu

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Cu

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With

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Re

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� V

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:(1

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stanta

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of 5

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require

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round fa

ults

ext

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.(2

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rizin

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for

67N

.(3

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nd 6

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rela

ys to

be a

rranged

for

trip

pin

g w

ith tw

o ti

me d

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yse

ttings

as

show

n.

(4)

Bre

ake

rs B

3-1

and B

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, and B

4-2

and B

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shall

trip

as

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of p

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trip

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cond. M

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sing a

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div

idually

shall

be p

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ded.

(5)

When b

reake

rs B

3-1

and B

4-2

are

open a

t sam

e ti

me, p

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ele

cted

genera

tor

neutr

al b

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hall

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matic

ally

to p

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de

15 K

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round.

27

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63

67

67N

67V

81

86

87 A PF

KW V FR

VR

KW R51

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90 K

V R

ate

d N

orm

al

93

KV

+ 8

0%

N.C

.

2500 M

VA

(M

ax)

1200 M

VA

(M

in)

22 1

51

50

51

50

51

N5

1N

51

G5

1G

36

MV

AW

ate

r C

oo

led

69

� 1

5.7

5 K

VT

CU

L +

12

%

N.C

.A

-41

, A

-42

B3

-1,

B4

-2

N.C

.

51

G5

0G

Note

1

CR

CR

VV

A-4

1A

-42

Auto

matic

Tra

nsf

er

IP 1

6-1

2-2

B 1

-2

63

86

87 T

3

CR

51

KW R

KW

KW

PF CR

51

G

CR

CR

Bus

1P

2

AA AS

1P

-2

51

1P

-22

AS A 51

G

81P

327

R

B1

-3

A AS

51

51

G

2 1

V V

VS C

R

CR

PFP

T

67V

SB

3-1

Bus

3P

3

A-4

1, B

1-2

1P

-2, B

1-3

B3-1

B1-3

A-4

2, B

1-2

2P

-2,

B2-4

3

87

R8

6R

87

-2

86

-2

87

-3

86

-3

B4-2

B2-4

B4-2

S

86

R8

7R

CR

CR

PT

2P

-23

51

G

51

12

V V

VS

ASA

B2-46

3

86

87 T

3

CR

Nor

mal

lyO

pen

51

G

27

R

2P

-2

2

51P

51

AS A

51

GIs

ola

ting

Tra

nsf

orm

er

Bus

4P

B3-4

B3-1

, B3-4

, 3P

-G1

3P

-4, 3

P-3

, 3P

-2N

ote 2

Note 3

Nor

mal

lyC

lose

d

86

-11

87

-1

3C

R

VV

CR

SW

CR

VS

81

87

N

67

67

87

N

PR

VR

CR

VVVS

87

-4

86

-4

B4-2

, B-4

, 4P

-G2

4P

-4, 4

P-3

, 4P

-2PF

67V

87

R5

1

AS

32

22 1

51

G

AA

A

AS

AS

50

G5

0G

25

15

15

05

06

7

67

N

Note

(Fig

ure

14)

(See F

igure

14)

Futu

re G

enera

tor

Genera

tor

Connect

ion

Tra

nsf

orm

er

Feeders

Bus

Feeder

Bus

Feeder

Syn

chro

niz

ing C

ontr

ol B

us

Bus

Feeder

Bus

Feeder

Bus

4P

Duplic

ate

Of

3P

-23P

-33P

-4

3P

-G1

32

87P

51

AS A

51

G

Note

(Fig

ure

14)

4-P

24-P

34-P

44P

-G2

CR C

RC

R

51

2

PF

KW

ASA

A

KW

KW R

Bus

2P

1000 M

VA

SS

SS

DP30Bf13

1st

2

nd

B 4

-2

B 3

-4 4 P

-G 2

4 P

-4 4 P

-3 4 P

-2

1st

2

nd

B 3

-1

B 3

-4 3 P

-G 1

3 P

-4 3 P

-3 3 P

-2





➧ FIGURE 14ONE-LINE DIAGRAM GENERATOR PROTECTION CONTRA-ROTATING STEAM TURBINE GENERATOR

15KV Bus 4P

4P-G2 S

V

F

A

KWKVARP.F.

PF

VR

EXA

EXV

ControlRoom

59

KWR

86G 87G

26

3095

95

46

51V

40

Note 6

Note 6

32SS

Note 3

50G51G2

Note 5

Note 4

TurbineShutdown

60G Note 4

FutureGenerator

And Control

64F

60F

Gen."A"

Gen."B"

19 MW@ 0.7PFXd = 159%X'd = 26%X"d = 10%

SurgeProtection

Future

Note 2

2

21

Note 1

26

30

32

40

46

50G

51V

51G

59

60G

60F

64F

67

86

67N

87G

95

A

LEGEND

Rotor Temperature Relay

Alarm Device

Reverse Power Relay

Loss Of Excitation

Negative Sequence

Instantaneous Ground

Time Overcurrent WithVoltage Restraint

Time Overcurrent, Ground

Overvoltage

Stator Interturn Fault

Rotor Ground Alarm

Rotor Winding Fault

Directional Overcurrent

Directional Overcurrent,Ground

Lockout Relay, Hand Reset

Differential

Timing Relay

Ammeter

Notes:

(1) Polarizing voltage from Bus PT's.(2) Aux. Bus PT's connected Grounded Wye-open Delta can

be used for for 67N polarizing voltage.(3) Automatic closing required when normal system ground

has been lost.(4) Two instantaneous contacts of 50G required to block 60G

during ground faults external to generators.

(5) Tripping by 51G shall use neutral breaker contacts to trip allbreakers connected to Bus with grounded neutral generator. B3-4to be tripped when either TG-1 or 2 is grounded. (See Figure 13)

(6) 51V and 46 tripping first isolates generator Bus. Second stagetrips all breakers on Bus if fault persists.

(7) TG-1 and TG-2 each have (2) 13.5 MVA generatorsconnected to one 19 MW steam turbine.

V

PF

KWKVARP.F.

F

SS

Excitation Ammeter

Excitation Voltmeter

Voltmeter

Power Factor Meter

Vector Meter

Kilowatt RecordingKWR

Frequency, Indicating

Selector Switch ForNeutral Breakers

Potential TransformerDrawout, Primary FusedWhere Shown

Current Transformer

15 KV Drawout CircuitBreaker "S" IndicatesSynchronizingRequirement.

67

67N

EXA

EXV

To BusbarDiff Protection

DP30Bf14






➧ LEGEND FOR FIGURE 15

Time Overcurrent withInstantaneous Element

Inst. Ground Fault Relay

Time Overcurrent

Time Overcurrent, Ground

Time Overcurrent withVoltage Restraint

Fault Pressure

Directional OvercurrentCurrent Direction

Direct. Overcurrent NeutralDefinite Time

Aux. Relay For 67

Lockout, Hand Reset

Lockout, Hand Reset

Differential

Differential, Neutral

Pilot-Wire

Pilot-Wire, Backup

Stuck breaker Fault Detector

DP30Bf15a

50 GS

50/51

51

51G

51V

63

67

67N

67x

86

86T

87

87N

85-1

85-2

50S

LEGEND FOR FIGURE 16

26

30

32

40

46

50G

51

5150

51G

51V

63

64

67

67N

81

86

87

95

A

AF

KV

VF

KVR

MW

MWR

MVARR

PF

FR

Rotor Temperature Relay

Alarm Device

Reverse Power Relay

Loss Of Excitation

Negative Sequence

Instantaneous Ground

Time Overcurrent

Time Overcurrentwith Instantaneous

Time overcurrent, Ground

Overcurrent with VoltageRestraint

Fault Pressure

Rotor Ground

Directional Overcurrent

Underfrequency forLoad Shedding

Lockout Relay Hand Reset

Differential

Directional Ground

Timing Device

Ammeter

Field Ammeter

Kilovolt Meter

Field Voltmeter

KV Meter Recording

Megawatt, Recording

Megavar Meter Recording

Megawatt Meter

Power Factor Meter

Located in Central ControlRoom

Drawout Circuit Breaker

Potential TransformerDrawout � with PrimaryFuse

Current Transformer

Zero Sequence CurrentTransformer

Frequency Recorder

Current Transformerwith polarity indicated

DP30Bf16a





➧ FIGURE 15ONE-LINE DIAGRAM SYSTEM PROTECTION COMPLEX MULTI-BUS SYSTEM

87/

87N

Pilo

t wire

To

Rem

ote

S/S

To

Rem

ote

S/S

End

Sta

ge

1st

Sta

ge

(67)

85-2

50S

85-1

87

A

67

63

86T

51G

87

2nd

Sta

ge

1st

Sta

ge

67

67N 13

.8 K

V

Trip O

ther

React

or

Bre

ake

rs

Syn

chro

niz

ing B

us

2nd

Sta

ge

67

67N

Trip

Genera

tor

Bre

ake

r.T

rip A

ll F

eeder

Bre

ake

rsV

ia B

us

Diff

86 R

ela

ys

2nd

Sta

ge

Genera

tor

Shu

tdow

n87N

87

86

G

51V

51G

1st

Sta

ge

67

67N

1st

Sta

ge

87

51G

86T

63

2nd

Sta

ge

To

Rem

ote

S/S

67

85-1

85-2

80S

2nd

Sta

ge

Pilo

t W

ire T

oR

emot

e S

/S

1st

Sta

ge

All

Rela

ying a

nd

CT

,s as

show

nfo

r B

us

Op

po

site

G

13.8

KV

50/5

1

87

87G

50 G

S

Tra

nsf

orm

er

Feeder

Tra

nsf

orm

er

Feeder

50/5

1

50 G

S

50/5

1

50 G

S

Tra

nsf

orm

er

Feeder

87

86 T

rip A

ll F

eeder

Bre

ake

rs O

nG

enera

tor

Sid

e O

f Bus

Tie

Bre

ake

r

DP30Bf15

86






➧ FIGURE 16ONE-LINE DIAGRAM SYSTEM TURBINE GENERATOR AND SYSTEM PROTECTION TWO MAIN BUS SYSTEM

Ne

utra

l Bus

Tri

pT

ieB

reak

er

Tim

eV

F

AF

KV R MW R

MV

AR

R PF

FR

AF A

A

VF

KV

MW

Syn

chro

niz

ing

Eq

uipm

ent

Sur

ge P

rote

ctio

n

12.5

MW

13 2

00 V

0.

8 P

F

No

te 1

51V

30

95 32

30 30 30 30

46 40 87G

DF

26 64

Dio

de

Fa

ilure86

E

861

Tri

p S

igna

lF

rom

Tur

bin

e

Tri

p G

ener

ato

rB

reak

er

Tri

p F

ield

Bre

ake

r

Tri

p G

ener

ato

rB

reak

er

Tri

pB

reak

er

Tri

p T

urb

ine

12.5

MW

13 2

00 V

0.

8 P

F

Met

erin

g A

nd

Pro

tect

ion

Sim

ilar

Met

erin

g A

nd

Pro

tect

ion

Sim

ilar

12.5

MW

13 2

00 V

0.

8 P

F

Gro

undi

ngR

esi

stor

51G

51G

To

Po

lariz

ing

CT

67N

67

1 2T

o 8

61

To

86

ET

o P

ola

rizin

g C

T

G1

13.

8 K

V

To

861

To

86

E

Bu

s A

To

Po

lariz

ing

CT

167

N

67

2

Syn

chro

niz

ing

Eq

uipm

ent

To

Po

lari

zin

g C

T

G2

81 LF KV

67N A

To

86B

TO

Po

lariz

ing

CT

81 LF KV

67N B

To

86A

Syn

chro

niz

ing

Eq

uipm

ent

No

rmal

lyC

lose

d

Bu

s B

67N

67

1 2

To

Po

lariz

ing

CT

To

Po

lariz

ing

CT

To

861

To

86

E

No

te 2

86B

87B

B1

B2

251 50

51 50

251 50

22

51 50

No

te 2

AS

AS

AS

AS A

AA

A

51 50

2

AS A

50G

50G

50G

50G

50G

A1

86A

87A

A2

A3

8663

50G

6386

50G

6386

50G

To

Bo

iler

Fe

ed P

um

p M

oto

r

Tra

nsf

orm

er

Fe

ede

rT

o A

uxi

liari

es' S

erv

ice

sS

ubs

tatio

n T

rans

form

ers

Tra

nsf

orm

er

Fe

ede

r(1

) O

ptio

nal

, to

be

verif

ied

(2)

86A

� T

rips

G1

,G2,

T,A

-1,A

-2,A

-3(3

) 8

6B �

Tri

ps G

3,T

,B-1

,B-2

No

tes

:

DP

30B

f16

30





➧ FIGURE 17ONE LINE DIAGRAM (TYPICAL) GAS TURBINE GENERATOR PACKAGE POWER PLANT

3- Phase Sequence1-2-3

2

31

52 T41 ETurb

Trip 86T

87T

51N

52

20 000 KVA

13.2 KV

1200/5(3)2PT's

14 400 � 120V

K

K

75 KVA

480 VTo Auxiliaries' Bus (Figure 18)

To Customer'sExisting Bus

(1) 1200/5

15 KV L.A.

Surge Cap..25 µf

14 400 � 20V

10A

VF

Auto SynchRelays

52G OR 52T

SYN

86G

87G

Voltage Adj.(Manual)

41ETurb

PPT TRIP

Voltage Set Point(Automatic Model)

MV

StaticExciterRegulator

GenField

TM

TMSW

20 000 KVA0.85 P.F.13 200 V 49

G

ALARM1200/5

1200/5

1200/5

(3)

(3)

(3)

(3) SCT

64G

10 KVA13 200 � 240 VoltNeutral GroundingTransformer

1.08 OHM205A1 Minute

Trip 52G or 52T

Trip 52G or 52T

Trip 86G40

32

21G

46

W

VAR

WH

AS A

V

0 � 18KV

VS

Auto Synch Relays+ Scope

Master Control Panel

Alarm

Flame

Sequence

VoltageControl

LoadControl

StartStop

Fast-LoadStart

CA70

CA1

CA1F

52G

CA90

W VAR V

40

32

27

21G

46

41 E

49G

51N

52T

52G

64G

72

86G

86T

87G

87T

VR

K

TM

V

W

SYN

M

A

F

VAR

WH

Generator External Fault

Undervoltage

Reverse Power

Loss Of Excitation

Exciter Field Contactor

Negative Sequence

Stator Temperature

Ground Fault

Transformer Breaker

Generator Breaker(When Provided)

Generator Ground

Dc Contactor

Generator Lockout

Transformer Lockout

Generator Differential

Transformer Differential

Voltage Regulator

Key Interlock

Temp Meter

Voltmeter

Wattmeter

Synchroscope

Motor Operator

Ammeter

Frequency Meter

Varameter

Watthour Meter

DP30Bf17

3 � Phase Bus

SCT Saturating Current Transfer

PPT Power Potential Transformer






FIGURE 18ONE LINE DIAGRAM (TYPICAL) GAS TURBINE GENERATOR

AUXILIARIES PACKAGE POWER PLANT

480 � Volt Motor Control Center

From Auxiliaries' SupplyTransformer (Figure 17)

480 � Volt Paneloard � 3 Phase

CooldownLube OilPump

Lube OilImmersion

Heater

TurbineComptHTR

AccessComptHTR

ControlComptHTR

GeneratorStripHTR

15 KW 15 KW 17.5 KW 15 KW 4.5 KW5

10 KVA

1 KW2.5 KWMain

TransformerFans Space HTR

Battery Compt

MCC UndervoltageRelay

110 � Volt Panelboard � 1 Phase

27MC

BatteryCharger

ImmersionHTR

Diesel Eng(If Used)

1/6

GenLouverDrives

GenCompt

52GX

LTGAccess

TurbGen

Compts

Space HTRSTurb+Gen

Pannel LTGRecept

Turb+GenPannel Space

HTRS

TurbineAir Filter

Drive

52TF

1/6

1/6

LTGControlCompt

AirCond

ConnOutlet

ConnOutlets

Access+Turb

Compt

SwitchgearSpace HTR

+ LTG

Purchaser'sOutdoor

LTG

125 V DC Pannelboard

125 V CD Battery

GenControl Panel

TurbineControl Panel

72 MGX

AirDryer

72 MGX 72 MG 72 72 27 MC

500VA

1HP

1 5

Rotary InverterFor

Black Start

M-G Set ControlAir

Compressor

Emerg LubeOil Pump

Turb &Gen

ControlPanels

EmergLTG

ControlCompt

Emerg LTGAccess+TurbineCompt

FromBatteryCharger

DP30Bf18





FIGURE 19RATE OF SPEED - DROP OF FULLY LOADED STEAM TURBINE GENERATOR

FOR VARIOUSLY SUDDENLY APPLIED EXCESS LOADS

50

55

60

0 0.2 0.4 0.6 0.8 1.0 1.2 1.4 1.6 1.8

Seconds

(Courtesy General Electric Co.)

Excess Load = 200%

Excess Load = 150%

Excess Load = 100%

Excess Load = 50%

Fre

que

ncy

� H

ert

z

DP30Bf19






APPENDIX A - LOAD SHEDDING CALCULATIONS

Settle Out Frequency - This is the frequency to which the system will drop if the overload is not removed and reflects theeffect of reduced frequency on loads.

Fs =OL1

OLd

1d1

Fn+

−+

Fs = Settle-out frequency

Fn = Normal system frequency

d = Ratio of load decay percentage to frequency decay percentage. The load decay is due tofrequency effect. Value used should be 2 unless specific data available.*

OL = Overload in per unit

RATE OF FREQUENCY DECAY

dt

dF=

sec

Hz)MWMW(

H2

Fn21 −

H = Sum of generator inertia constants in kW-sec on total generated kVA base, kW-sec/kVA

Fn = System frequency

MW1 = Per unit generated torque (MW1) and load torque (MW2 ) expressed as MW on the totalgenerated

MW2 = MVA base.

INERTIA CONSTANT - INDIVIDUAL UNIT

H = sec/kVAkWkVARated

10)rpm()Wk(231.0 622

−−

Wk2 = Inertia constant in Lb • Ft2

rpm = Rated speed, revolutions per minute

* Data from one ExxonMobil plant showed a 2.5 for a combined 2% reduction in frequency and 2.5% reduction in voltage.

Time to Reach Specific Frequency - The time to reach a specific frequency can be used to determine the initial rate offrequency decay and is used in underfrequency relay settings. It can be calculated from the relationship:

o

21

1AV f

f1DtL

H

PF −=

PF = Load power factor in per unit

LAV = Average overload between f0 and f1 (reflecting effect of �d" factor) in per unit and is calculated from (Lo + L1)/2

H = Inertia constant, kW-sec/kVA

f1 = Specific frequency

f0 = Initial frequency

∆t = Time in seconds between f0 and f1

Since LAV is the average load between two frequencies, calculation should be made using small frequency intervals such as 0.5Hz or 1 Hz.

In setting of underfrequency relays, the procedure is to determine time elapsed to pickup of first underfrequency relay setting,then time to actual load shed (including relay and auxiliary relay and breaker trip delays) and actual load at that point whenshedding occurs (due to continued frequency delay), time to initiation of next step, actual load at trip of the next step, etc. Thereference paper by Fountain and Blackburn provides details on the calculation procedure.





APPENDIX BREPRESENTATIVE DESIGN SPECIFICATION FOR COMPLEX MULTI-GENERATOR EXPANSION

DESIGN BASIS

• Operation of system and bases for operation under normal and abnormal conditions. Specified limiting parameter ofminimum voltage on generation bus during public utility faults.

• Location of system control for new and existing turbine generators.

• Substations served from power plant and their control.

• Unit boiler-turbine generator concept.

• Bases for instrument power supply.

• Plans for future expansion.

• Public utility short circuit levels and voltage regulation.

GENERAL

• Reference to project specifications and applicable equipment standards.

• Qualifications on one-line diagrams as representative diagrams.

• Contractors responsibility for verification, interfaces, etc.

REQUIRED SYSTEM STUDIES

• Protective Relaying

• System Stability

• Load Shedding

• Reacceleration

• Effect of Planned Future Expansion

• Cable type study

• Ferroresonance interaction between long cable connection and tie transformer at transmission system voltage level.

• Listing of stability, load flow and short circuit studies already carried out on existing system and expanded system.

REQUIREMENTS FOR STEAM TURBINE GENERATORS AND ASSOCIATED FACILITIES

• Turbine vendor responsibility for train.

• Turbine-boiler unit connection.

• Generator base load operations.

• Turbine type - back pressure with uncontrolled extraction - direct coupled.

• Short circuit withstand capability.

• Steam conditions - flow, pressure, temperature, normal, maximum and minimum for inlet, exhaust and extraction, and inletpressure and temperature variations.

• Performance curve requirement.

• Requirements for turbine shaft seals, qualification on use of a-c auxiliaries, governing and emergency governor, trip andthrottle valve, and speed changing mechanism.

• Lube oil system requirements.

• Turbine local board requirements.






APPENDIX BREPRESENTATIVE DESIGN SPECIFICATION FOR COMPLEX MULTI-GENERATOR EXPANSION (Cont)

• Equipment mounted instrumentation.

• Turbine remote panel location and requirements.

• Alarms and trips - turbine and accessories.

• Testing - turbine and components.

• Generator characteristics - size, voltage, frequency, MW and MVA rating.

• Requirement to optimize MVA size and power factor for motor starting and reacceleration.

• Stator connection and insulation class, rotor insulation class.

• Generator cooling type and requirements for coolers.

• Requirement for shaft seals, resistance temperature detectors, fire protection, etc.

• Excitation continuous and short time rating.

• Voltage regulator requirements.

• Location of excitation and voltage regulation components.

• Surge protection.

• Generator terminals enclosures requirements.

• Instrumentation and alarms - generator and accessories.

• Testing - generator, exciter and auxiliaries.

• Data submission.

ELECTRICAL DISTRIBUTION AND CONTROL FACILITIES

• One-line diagram scope and contractors responsibilities with respect to equipment selection and completeness.

• Distribution system operation for normal and abnormal conditions and transient limitations.

• Proposed normal switching procedure.

• Electrical system control including generator loading, location of control for new and existing units, locations for circuitbreaker control, location for start-up and normal operation, proposed operation of voltage regulators and on-load tapchangers for normal and abnormal conditions, and load shedding provisions.

• Synchronizing equipment requirements.

• Interlocking and protection for turbine generator and auxiliaries, boiler-turbine unit auxiliaries, station services and publicutility tie circuits.

• Description of protective relay functions.

• Metering requirements and location.

• Switchgear control locations.

• Power plant main distribution substation requirements.

• Bus tie reactor equipment and operational requirements needed to select reactance, voltage regulation, range andcontinuous and overload capability.

• Feeder reactor requirements.

• System grounding type, number of grounded sources and source normally grounded, requirements for automatic switchingon loss of normal source and sensitivity of generator differential protection.

• Requirements for public utility tie feeders and tie transformers.

• Requirements for power plant auxiliaries substations.

POWER PLANT BLOCK CONTROL AND METERING

• Requirement specification for panel and console section and listing of location for overall refinery and chemical complexreal and reactive power metering and totalizing.





APPENDIX BREPRESENTATIVE DESIGN SPECIFICATION FOR COMPLEX MULTI-GENERATOR EXPANSION (Cont)

EQUIPMENT, BUILDINGS AND CONSTRUCTION PROCEDURES

• Parameters for major equipment sizing.

• Voltage level and horsepower split.

• Motor reacceleration requirements.

• Power plant proposed layout.

• Wiring methods.

LOAD SUMMARY

• Main distribution substation.

• Main offsite substations.

• Power plant auxiliaries substations.

• Summary by service for power plant loads.

TYPICAL APPENDICES

• API RP612 turbine, gear and lube system data sheets.

• Turbine information to be submitted by Vendor.

• Synopsis of results of ER&E computer calculations for stability and reactor sizing check, tabulation of generator constantsused, and diagram of excitation model used.

• IEEE paper 31 TP67-424, �Computer Representation of Excitation Systems."

dp30b

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