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CONTENTS 1 SCOPE ....................................................................................................................................................... 5 2 REFERENCES............................................................................................................................................ 5 2.1

GLOBAL PRACTICES ................................................................................................................... 5

2.2

OTHER LITERATURE ................................................................................................................... 5

3 BACKGROUND.......................................................................................................................................... 6 4 DEFINITIONS ............................................................................................................................................. 6 5 PROTECTIVE DEVICE TYPES AND APPLICATION ................................................................................ 8 5.1

DIRECT ACTING TRIPS................................................................................................................ 8

5.2

FUSES ........................................................................................................................................... 8

5.3

RELAYS - GENERAL................................................................................................................... 10

5.4

MICROPROCESSOR-BASED RELAYS ...................................................................................... 11

5.5

RELAYS - DEVICE DESCRIPTIONS........................................................................................... 12

5.6

TIME DELAY RELAYS (2) AND (62)............................................................................................ 12

5.7

DISTANCE RELAYS (21)............................................................................................................. 12

5.8

VOLTS / HERTZ RELAYING (24) - OVEREXCITATION PROTECTION ..................................... 13

5.9

SYNCHRONIZING RELAYS (25)................................................................................................. 13

5.10 TEMPERATURE RELAYS (26).................................................................................................... 14 5.11 UNDERVOLTAGE RELAYS (27) ................................................................................................. 14 5.12 DIRECTIONAL POWER RELAY (32)........................................................................................... 14 5.13 LOSS OF FIELD RELAYS (40) .................................................................................................... 14 5.14 NEGATIVE-SEQUENCE OVERCURRENT RELAYS (46) - GENERATOR PROTECTION......... 15 5.15 PHASE BALANCE RELAYS (46) - MOTOR PROTECTION ........................................................ 15 5.16 NEGATIVE SEQUENCE VOLTAGE RELAYS (47) - MOTOR PROTECTION............................. 16 5.17 THERMAL OVERLOAD RELAYS (49) AND LOCKED ROTOR PROTECTION .......................... 16 5.18 INSTANTANEOUS OVERCURRENT RELAYS (50).................................................................... 18 5.19 INVERSE TIME OVERCURRENT RELAYS (51) ......................................................................... 18 5.20 DEFINITE TIME OVERCURRENT RELAYS (51) ........................................................................ 19 5.21 VOLTAGE-RESTRAINED (VOLTAGE-CONTROLLED) OVERCURRENT RELAYS (51V)......... 19 5.22 OVERVOLTAGE RELAYS (59).................................................................................................... 20 5.23 VOLTAGE BALANCE RELAY (60) / PT FUSE FAILURE ............................................................ 20 5.24 BUCHHOLZ AND SUDDEN PRESSURE RELAYS (63).............................................................. 20 5.25 DIRECTIONAL OVERCURRENT AND POWER RELAYS (67 AND 32)...................................... 21 5.26 FREQUENCY RELAYS (81) ........................................................................................................ 21 5.27 PILOT-WIRE RELAYS (85).......................................................................................................... 21 5.28 LOCKOUT RELAYS (86) ............................................................................................................. 22 5.29 DIFFERENTIAL RELAYS (87) ..................................................................................................... 22 5.30 GROUND (EARTH FAULT) RELAYS (50N, 50G, 50GS, 51N, 51G, 51GS, 67N)........................ 23

This information is considered CONFIDENTIAL and shall not be released to or discussed with any persons except (a) employees of ExxonMobil Affiliates who have an appropriate research agreement with ExxonMobil Research and Engineering Company (EMRE), and (b) consultants, contractors, or employees of third parties with whom proper secrecy agreements have been executed with EMRE or such ExxonMobil Affiliates. ExxonMobil Research and Engineering Company

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6 CURRENT TRANSFORMERS ................................................................................................................. 24 6.1

CORE BALANCED (ZERO SEQUENCE) CURRENT TRANSFORMERS................................... 26

7 POTENTIAL TRANSFORMERS............................................................................................................... 26 8 BASIC DESIGN CONSIDERATIONS....................................................................................................... 26 8.1

PROTECTION PHILOSOPHY...................................................................................................... 26

8.2

OVERCURRENT DEVICE COORDINATION (SELECTIVITY / DISCRIMINATION).................... 27

8.3

BACK-UP PROTECTION............................................................................................................. 28

8.4

GROUND (EARTH) FAULT RELAYING ...................................................................................... 28

8.5

MOTOR PROTECTION ............................................................................................................... 29

8.6

GENERATOR PROTECTION ...................................................................................................... 30

8.7

TRANSFORMER PROTECTION ................................................................................................. 30

8.8

TRANSFORMER SECONDARY PROTECTION.......................................................................... 31

8.9

POTENTIAL TRANSFORMER PROTECTION ............................................................................ 31

8.10 BUSBAR PROTECTION.............................................................................................................. 31 8.11 CABLE (FEEDER) PROTECTION............................................................................................... 31 8.12 SECONDARY SELECTIVE SUBSTATION PROTECTION ......................................................... 32 8.13 SPOT NETWORK SUBSTATION PROTECTION........................................................................ 32 8.14 RESTRICTED EARTH FAULT PROTECTION ............................................................................ 33 8.15 CAPTIVE TRANSFORMER PROTECTION................................................................................. 33 8.16 CALCULATION PROCEDURE .................................................................................................... 33 8.17 DOCUMENTATION REQUIRED FROM CONTRACTOR............................................................ 33 8.18 WHEN CONTRACTOR SHOULD FURNISH RELAY DOCUMENTATION.................................. 33 8.19 SAMPLE RELAY DATA AND COORDINATION.......................................................................... 34 8.20 RELAY DATA REQUIREMENTS................................................................................................. 34 8.21 RELAY COORDINATION REQUIREMENTS............................................................................... 34 8.22 SQUIRREL CAGE INDUCTION MOTOR RELAY SETTINGS..................................................... 35 8.23 MCC FEEDER RELAY SETTINGS.............................................................................................. 36 8.24 TRANSFORMER-SECONDARY RELAY SETTINGS.................................................................. 36 8.25 TRANSFORMER PRIMARY RELAY SETTINGS ........................................................................ 36 8.26 SECONDARY-SELECTIVE AUTO-TRANSFER RELAY SETTINGS .......................................... 37 8.27 GENERATOR RELAY SETTINGS............................................................................................... 38 8.28 GENERATOR SEPARATION RELAY SETTINGS....................................................................... 39 8.29 SPOT NETWORK RELAY SETTINGS ........................................................................................ 39 8.30 PARTIAL DIFFERENTIAL RELAY SETTINGS ............................................................................ 40 8.31 RESTRICTED EARTH FAULT PROTECTION ............................................................................ 40 9 IEEE STANDARD ELECTRICAL DEVICE FUNCTION NUMBERS ........................................................ 42 9.1

DEVICE NUMBERS ..................................................................................................................... 42

9.2

SUFFIX LETTERS ....................................................................................................................... 45

9.3

SUFFIX NUMBERS...................................................................................................................... 49

9.4

DEVICES PERFORMING MORE THAN ONE FUNCTION.......................................................... 49

This information is considered CONFIDENTIAL and shall not be released to or discussed with any persons except (a) employees of ExxonMobil Affiliates who have an appropriate research agreement with ExxonMobil Research and Engineering Company (EMRE), and (b) consultants, contractors, or employees of third parties with whom proper secrecy agreements have been executed with EMRE or such ExxonMobil Affiliates. ExxonMobil Research and Engineering Company

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9.5 PER UNIT SYSTEM..................................................................................................................... 49 9.5.1 Definitions:.............................................................................................................................. 49 9.5.2 Basic Formulas:...................................................................................................................... 50 9.6

CONVERSIONS AND CALCULATIONS...................................................................................... 50

APPENDIX Appendix A - Symbols ................................................................................................................................... 52

TABLES Table 1 I.E.C. Recommended Fuse Ratings For Low Voltage .................................................................... 41 Table 2 Typical Current Transformer Ratios................................................................................................. 41 Table 3 IEEE Standard Device Numbers ..................................................................................................... 42

FIGURES Figure 1 - Definition Of Knee Point................................................................................................................ 55 Figure 2 - Current Limiting Fuse.................................................................................................................... 56 Figure 3 - Instantaneous Relay Current vs Time Curve With Or Without D.C. Filter .................................... 57 Figure 4 - Instantaneous Relay Current vs. Time Curve Sensitive To Current Offset (D.C.)......................... 58 Figure 5 - Instantaneous Relay Current Vs. Time Curve With D.C. Component Filtered Out ..................... 59 Figure 6 - Instantaneous Relay Overreach Vs. System Angle...................................................................... 59 Figure 7 - Instantaneous Relay Operating Time Vs. Current........................................................................ 60 Figure 8 - Typical Time vs. Current Curves Of Relays With Inverse Time Characteristics............................ 61 Figure 9 - Inverse Time Overcurrent Relay Slopes ....................................................................................... 62 Figure 10 - Definite Time Overcurrent Relay Time vs. Current Curve ........................................................... 62 Figure 11 - Generator Cable Protection With Directional Relay .................................................................... 63 Figure 12 - Generator Cable Protection With Differential Relay .................................................................... 64 Figure 13 - Cable Differential Protection ....................................................................................................... 65 Figure 14 - Transformer Differential Protection ............................................................................................. 65 Figure 15 - Generator Or Motor Differential Protection.................................................................................. 66 Figure 16 - Busbar Differential Protection ..................................................................................................... 66 Figure 17 - Standard Differential Protection .................................................................................................. 67 Figure 18 - Pilot Wire Differential Protection.................................................................................................. 67 Figure 19 - Distance (Impedance) Protection ................................................................................................ 68 Figure 20 - Time Grading Selectivity ............................................................................................................. 69 Figure 21 - Current Grading .......................................................................................................................... 70 Figure 22 - Selectivity Between Fuses .......................................................................................................... 71 Figure 23 - Instantaneous Relay Set Point.................................................................................................... 72 Figure 24 - Instantaneous Relay Operation At Less Than Half A Cycle ........................................................ 72 This information is considered CONFIDENTIAL and shall not be released to or discussed with any persons except (a) employees of ExxonMobil Affiliates who have an appropriate research agreement with ExxonMobil Research and Engineering Company (EMRE), and (b) consultants, contractors, or employees of third parties with whom proper secrecy agreements have been executed with EMRE or such ExxonMobil Affiliates. ExxonMobil Research and Engineering Company

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Figure 25 - Selectivity Between An Instantaneous Relay And A Current Limiting Fuse ................................ 73 Figure 26 - Fuse Peak Let-Through Current Curves ..................................................................................... 74 Figure 27 - Backup Protection ....................................................................................................................... 75 Figure 28 - Motor Control Circuits ................................................................................................................. 76 Figure 29 - Transformer Protection ............................................................................................................... 77 Figure 30 - Partial Differential Protection....................................................................................................... 78 Figure 31 - Relay Settings Record ................................................................................................................ 79 Figure 32 - Relay Coordination Graph Paper ................................................................................................ 80 Figure 33 - Relay Coordination Sample One Line Diagram .......................................................................... 81 Figure 34 - Typical Relay Settings Record .................................................................................................... 82 Figure 35 - Typical Relay Settings Record (13.8 Kv/480 V) .......................................................................... 84 Figure 36 - Typical 2400v Phase Relaying Curves........................................................................................ 86 Figure 37 - Typical 2400v Ground Relaying Curves...................................................................................... 87 Figure 38 - Typical 2400v Motor Relaying Curves......................................................................................... 88 Figure 39 - Typical 480v Phase Relaying Curves.......................................................................................... 89 Figure 40 - Typical 480v Ground Relaying Curves........................................................................................ 90 Figure 41 - Typical 480v Turnaround Power Center Relaying Curves .......................................................... 91 Figure 42 - Stabilizing Resistor...................................................................................................................... 92 Figure 43 - Typical Fuse I2t Characteristics .................................................................................................. 93 Figure 44 - Relative Magnitudes Of Fault Currents ....................................................................................... 94 Figure 45 - Typical X/R Values...................................................................................................................... 95 Figure 46 - Logic Diagram Using Standard Symbols (Partial) ....................................................................... 96 Figure 47 - Spot Network Relaying (Partial) .................................................................................................. 97

Revision Memo 10/04

Highlights of this revision are:

1. 2.

Added more IEEE and IEC reference standards. Added transfer blocking requirement for high-resistance grounded substations. 3. Clarified documentation requirements in Microprocessor-Based Relay section. 4. Stressed need to test ground fault relays at commissioning. 5. Added calculation of saturation in Current Transformer section and mentioned 'overdimensioning' of CT's. 6. Recommended 2 out of 3 tripping for critical motor undervoltage protection. 7. Added section on potential transformer fusing. 8. Added requirement for relay narrative to contractor relay documentation. 9. Recommended minimum pickup tripping time for motor 50 GS and 50N relays. 10. Added relay discussion for spot-network substations.

This information is considered CONFIDENTIAL and shall not be released to or discussed with any persons except (a) employees of ExxonMobil Affiliates who have an appropriate research agreement with ExxonMobil Research and Engineering Company (EMRE), and (b) consultants, contractors, or employees of third parties with whom proper secrecy agreements have been executed with EMRE or such ExxonMobil Affiliates. ExxonMobil Research and Engineering Company

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SCOPE

This section outlines our approach to system and equipment protective relaying from the power source, as defined in DP XXXC, to the loads. Design details of relays and calibration procedures are not covered. For this information, reference should be made to the manufacturer's instruction bulletins for each particular relay. Startup, commissioning and maintenance of protective relaying are covered in the "Electrical Equipment Acceptance and Maintenance Manual" TMEE064. Specialized protective relaying, such as for instruments and d-c circuits, are not included. 2 2.1

GLOBAL PRACTICES

GP 16-02-01

Power System Design

GP 16-04-01

Grounding and Overvoltage Protection

GP 16-07-01

Motor Application

GP 16-09-03

Synchronous Generators

GP 16-10-01

Power Transformers

GP 16-11-01

Neutral Grounding Resistors

GP 16-12-01

Switchgear, Control Centers, and Bus Duct

GP 16-12-02

Control of Secondary Selective Substations with Automatic Transfer

GP 16-13-01

Field Installation and Testing of Electrical Equipment

2.2 ç

REFERENCES

OTHER LITERATURE

ABB, Protective Relaying Theory and Applications ANSI/IEEE, IEEE Guide for Protective Relay Application to Power System Busses, C37.97-2000 ANSI / IEEE, IEEE Guide for Protective Relay Applications to Power Transformers, C37.91-2000 ANSI / IEEE, IEEE Guide for AC Motor Protection, C37.96-2000 ANSI / IEEE, IEEE Guide for AC Generator Protection, C37.102-1996 ANSI / IEEE, IEEE Guide for Protective Relay Applications to Transmission Lines, C37.113 ANSI / IEEE, IEEE Guide for Application of Current Transformers Used for Protective Relaying Purposes, C37.110-1996 ANSI / IEEE, IEEE Recommended Practice for Protection and Coordination of Industrial and Commercial Power Systems, Std 242-1986 IEEE Transactions, Allowing for Decrement and Fault Voltage in Industrial Relaying, IGA March/April 1965, pp. 130 - 139 IEC 60044-1 Instrument transformers - Part 1: Current transformers IEC 60044-6 Instrument Transformers - Part 6: Requirements for Protective Current Transformers for Transient Performance IEC 60255-3 Electrical Relays - Part 3: Single Input Energizing Quantity Measuring Relays with Dependent or Independent Time IEC 60269-1, -2 , Low-Voltage Fuses Beeman, D., Industrial Power Systems Data Book, published by McGraw-Hill GEC Measurements, Protective Relays Application Guide (PRAG), GEC, U.K. C.Russell Mason, Art and Science of Protective Relaying, http://www.geindustrial.com/pm/notes/artsci/index.htm This information is considered CONFIDENTIAL and shall not be released to or discussed with any persons except (a) employees of ExxonMobil Affiliates who have an appropriate research agreement with ExxonMobil Research and Engineering Company (EMRE), and (b) consultants, contractors, or employees of third parties with whom proper secrecy agreements have been executed with EMRE or such ExxonMobil Affiliates. ExxonMobil Research and Engineering Company

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BACKGROUND

Protective relaying is essential to maintain the integrity of the electrical system during a fault or other abnormal conditions. Even a well designed and maintained system can perform poorly if the protective relaying is not properly applied. During normal operation of an electrical system, the protective relaying is dormant and does not contribute to the reliability, hence deficiencies, such as defective relays, disconnected wiring, design errors, or incorrect settings, can go undetected for a long time (maybe years). However, when there is a fault or other abnormal condition on the electrical system, it is essential that the faulty equipment or circuit be disconnected by the protective relaying in the shortest possible time, otherwise the whole system may collapse. Because the protective relaying is so important and because we accept that nothing can be perfect, we apply additional protection to back-up the first line protection that will:

· Isolate the faulty equipment a short time after the primary relaying should have operated and/or · Isolate the faulty equipment by disconnecting the supply to it at a point further from the fault than the primary protection would have done.

Protective relaying should be designed to cover the worst possible scenario to fulfill its function of protecting the electrical system. This entails checking that it will operate correctly for all system configurations that are possible. In some unusual cases it may be necessary to sacrifice coordination to achieve faster clearing times for example Figure 1 and 2 of GP16-02-01. These cases should be limited to an absolute minimum and the reasons for it should be documented in the design notes for the project. 4

DEFINITIONS

Burden The term used for the electrical load on the secondary of a current transformer, including the resistance of the secondary winding. The burden is either expressed in ohms (with resistance and reactance components), or in volt-amperes at a specified power factor and current (usually the rated amperes of the device or the relay tap). Device Numbers The American numbering system for electrical devices is in the section entitled IEEE STANDARD ELECTRICAL DEVICE FUNCTION NUMBERS. Fault As used herein, a fault is a short circuit that causes a very high current flow, which is generally considerably in excess of rated current for the equipment or circuit. Fault currents are high enough to operate a protective device to isolate the “fault" within two seconds. GP 16-02-01 defines the distinction between an overload and a fault, as follows: “Overload vs. fault protection, as used in discussing selectivity, refers to the parts of relay, device, or fuse time-current characteristics respectively above and below two seconds." High-Resistance Neutral Grounding A system where the ground fault current is limited to such a low value that it can flow for several hours without damage to equipment. Ground relaying is not fitted on such a system except for ground fault detection alarm. Ground fault current is normally limited to 10 amperes maximum, but no more than 5 amperes is preferred. To avoid transient overvoltages, the ground fault current through the resistor must be equal to or slightly greater than 3 times the future maximum per-phase charging current to ground of the system to which it is directly connected; i.e., not including parts of the system separated from the ground source by isolation transformers that are open circuits in the zero sequence network. This makes the resistor ground fault current about equal to the capacitive ground fault current, and makes the total ground fault current about 1.414 times the resistor's fault current. Thus the future maximum per-phase charging current to ground of the (zero sequence isolated) system can be no more than 2.35 A (preferably 1.18 A) for a high resistance grounding application. This usually limits the application of high resistance grounding to a generator with a unit transformer, or a small low-voltage system. If a double-ended substation is This information is considered CONFIDENTIAL and shall not be released to or discussed with any persons except (a) employees of ExxonMobil Affiliates who have an appropriate research agreement with ExxonMobil Research and Engineering Company (EMRE), and (b) consultants, contractors, or employees of third parties with whom proper secrecy agreements have been executed with EMRE or such ExxonMobil Affiliates. ExxonMobil Research and Engineering Company

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involved, ground fault detectors must be employed in order to block manual and automatic transfer, when ground faults are present on both busses, to prevent a phase-to-phase fault at the moment of transfer. Knee Point (Knee Voltage) The knee point is that point of a current transformer excitation curve at which a further increase of 10% of secondary e.m.f. would require an increment of exciting current of 50%. See Figure 1. For most relaying applications, acceptable accuracy is obtained only when operation is below the knee point. Low-Resistance Neutral Grounding A system where the ground fault current is limited by a resistor connected between the system neutral and ground to reduce damage to equipment by ground faults, but where the current is high enough to operate ground protective relays reliably. Per GP 16-02-01, the neutral resistor must be sized to produce a ground fault current at least 15 times the lowest reliable operating current of the least sensitive outgoing feeder ground relay, and at least 5 times the lowest reliable operating current of bus ground relaying. To avoid any possibility of the ground fault current being low enough to cause transient overvoltages greater than 2.5 times the normal crest voltage to ground, the ground fault current should be at least 6.6% of the maximum 3-phase fault current. This ground-fault magnitude basis yields roughly the same order of magnitude ground-fault current as the 5-times rule in the previous sentence. Overload A current that is in excess of the rated value specified for a piece of equipment for the conditions under which it is operating, but not a high enough current to be considered a “fault." Examples of overloads are a pump with a higher viscosity fluid than design, and a transformer with too many loads connected. Overreach (Transient Overreach) Applied to instantaneous overcurrent relays and impedance relays, where for various reasons a relay operates for faults beyond the zone it was intended to cover (reach); i.e., the relay overreaches (see faults farther away than intended by the relay setting). Overreach of an instantaneous overcurrent (50) relay relates to the relay's sensitivity to asymmetrical amperes. A 50 relay sensitive to d-c offset can operate even though the symmetrical value of an offset current is below the relay's symmetrical setting. The typical application of overreach in our operations is to set a 50 relay on a transformer primary so it does NOT operate for a fault on the transformer secondary. To achieve this, the relay must be set above a multiple of the transformersecondary symmetrical rms fault current (IF) as seen by the relay. The multiple accounts for the instantaneous relay's overreach. In practice, a 50 relay that is fully sensitive to dc offset is set at about 190% to 200% of the reflected secondary-side symmetrical fault level; while a 50 relay with low overreach is set about 10% to 20% higher than IF times the quantity (1 + % overreach/100), where the % overreach is defined by the relay manufacturer, such as in Figure 6. Overtravel (Overshoot) Time A time interval associated with time-delayed overcurrent relays related to the relay completing its operation even though the input to the relay is removed prior to the specified operating time. For example, if for a given current, the relay operates in 0.8 seconds, but the relay operates even though the input current lasts only 0.75 seconds, the overtravel time is 50 milliseconds. The maximum overtravel time of an upstream relay must be factored into the discrimination interval between this upstream relay and a downstream overcurrent device to ensure that the upstream device does not operate when the downstream device correctly interrupts the overcurrent. The overshoot time of a relay is provided by the relay manufacturer, and can be as low as 30 milliseconds for solid state relays, and as high as 100 milliseconds for electromechanical relays. Secondary-Selective Substation A secondary selective substation has two busses, each supplied by a normally-closed incoming circuit breaker, and connected together by a normally-open bus tie breaker. In our designs per GP 16-12-02, the loss of supply upstream of one incoming breaker results in automatic opening of that incoming breaker, followed by closing of the tie breaker after the “dead" bus' residual voltage has decayed to a safe level.

This information is considered CONFIDENTIAL and shall not be released to or discussed with any persons except (a) employees of ExxonMobil Affiliates who have an appropriate research agreement with ExxonMobil Research and Engineering Company (EMRE), and (b) consultants, contractors, or employees of third parties with whom proper secrecy agreements have been executed with EMRE or such ExxonMobil Affiliates. ExxonMobil Research and Engineering Company

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Selectivity / Coordination/Discrimination Selectivity describes a protective system that has been designed and adjusted such that the protective device nearest to the fault operates first to clear the fault, and its setting allows an adequate margin of safety so that a protective device farther from the fault does not operate for the same fault. As the relay coordination procedure commences at the load and works back to the power source, we generally say an upstream device is selective with a downstream device. Spot-Network Substation A spot network substation has a main bus (with or without a normally-closed tie breaker), which is supplied by two normallyclosed incoming breakers. Tripping of one incoming breaker due to an upstream fault leaves the entire substation load on the other incomer without the transfer of load required for secondary-selective substations. A relayed tie breaker is provided when it is important to maintain supply to the loads on one of the busses for a bus fault or uncleared feeder fault on the other bus. 5 5.1

PROTECTIVE DEVICE TYPES AND APPLICATION

DIRECT ACTING TRIPS

A direct-acting-trip circuit breaker uses abnormally high current flowing into the breaker to initiate a time-delayed or instantaneous response which causes a direct acting operating mechanism to mechanically trip the breaker, without the need for external current transformers and relays. The time-current characteristic of a direct-acting-trip breaker is a band, the upper boundary of which indicates the maximum total clearing time of the breaker for a given current, while the lower boundary indicates the minimum clearing time. Direct acting trip units may be electromechanical (thermal-magnetic) or solid-state electronic. They are used in molded-case/insulated-case circuit breakers; and they are also used in low-voltage switchgear circuit breakers in the following applications:

·

For all outgoing feeder breakers, such as to MCCs, TAPCs, transformers, and typically to motors that would require larger than a size 4 starter. For motor feeders, the direct acting trip of a switchgear circuit breaker must be backed up with a thermal-overload (49) relay in one phase.

·

With Owner's Engineer approval, for the 51 and 51N functions of secondary-selective incoming breakers. The 51N ground fault function is available in direct acting trips with internal current transformers. The 50 and 50N functions must be relays.

·

Incoming breakers in radial and primary selective substations.

·

Incoming and outgoing circuit breakers in conjunction with auto-reclose.

This last application, which we have in use in Europe, permits instantaneous tripping on both incoming and outgoing circuit breakers. The circuit breakers have a one shot auto-reclose if immediately upstream of the load instantaneous protection, and two shot auto-reclose if located upstream of a one shot auto-reclose circuit breaker. In this application, the circuit breakers are usually current limiting. GP 16-12-01 states: “Selective reclosure for current limiting breakers is acceptable only if approved by the Owner's Engineer." If this is employed, the relaying downstream of the circuit breaker with the instantaneous direct acting trip must be arranged for the motors to “ride through" the disturbance or auto restart. 5.2

FUSES

Fuses are simple and reliable fault interrupters. They are less expensive than circuit breakers, but they cannot be re-used and cannot be tested. The types of fuses most often used in our installations are current limiting, which means that above a given fault level, the fuse will interrupt the fault current before it reaches its first peak. By limiting the magnitude and duration of fault current, current-limiting fuses minimize stress and damage to equipment, and can allow use of less expensive equipment downstream of the fuse. The typical use of current-limiting fuses is in motor starters, in general-purpose feeder protection, and in the protection of transformers (usually smaller than 500 kVA in ExxonMobil designs). When a current-limiting fuse operates for currents in its current-limiting range, it can be characterized by its peak let-through current (see Figure 2), and by its minimum melting and total clearing I2t characteristics (discussed below).

This information is considered CONFIDENTIAL and shall not be released to or discussed with any persons except (a) employees of ExxonMobil Affiliates who have an appropriate research agreement with ExxonMobil Research and Engineering Company (EMRE), and (b) consultants, contractors, or employees of third parties with whom proper secrecy agreements have been executed with EMRE or such ExxonMobil Affiliates. ExxonMobil Research and Engineering Company

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When a current-limiting fuse operates for currents below its current-limiting range, it can be characterized by its time-currentcharacteristic (TCC) curves, which are similar to those of other fuses. The melting time of a fuse (sometimes referred to as pre-arcing time) is the interval from the inception of a given fault current up to the time that melting of the fuse element is sufficient for arcing to just begin. The minimum melting curve provided by the fuse manufacturer shows the least amount of time it takes for a given current to melt an unloaded fuse in its non-current-limiting range of operation. The fuse manufacturer provides information on how to adjust the minimum-melt curve to account for preloading and other variables. The adjustment is current-based and moves the minimum-melt curve to the left. The minimum melting curve is used to coordinate the fuse with downstream protective devices for fault levels below the fuse's current limiting threshold. The minimum melting curve is also used to avoid fuse melting during motor starting or transformer energization. See the discussion of I2t below for current limiting operation. The total clearing time of a fuse is the interval from the inception of the fault to the time the fault is completely interrupted. The total clearing curve provided by the fuse manufacturer shows the maximum time it takes the fuse to completely clear any given constant fault current in the fuse's non-current-limiting range of operation. The fuse's total clearing time curve is used to coordinate upstream time-delayed protective devices with the fuse for currents less than the fuse's current-limiting threshold. See the discussion of I2t below for current limiting operation. Average melting curves are sometimes provided by a fuse manufacturer. These curves have a plus or minus tolerance of 10% on current for any given time. Thus the minimum melting curve is 10% lower in current than the average melting curve, and the maximum melting curve is 10% higher. For times greater than about 0.1 second, the maximum melting curve is essentially the same as the total clearing curve. If coordination with an upstream time-delayed device were questionable in the time between 0.1 second and 0.01 second, the estimated arcing time would have to be added to the maximum melting curve to approximate the total clearing time. For fault clearing times of one half cycle or less (e.g., below 0.01 second at 50 Hz), the peak let-through or I2t characteristics of the current-limiting fuse should be used. Total clearing I2t and minimum melting I2t data can be used for coordinating fuses in their current-limiting range. Two current limiting fuses connected in series coordinate when the downstream fuse's total clearing I2t is less than the upstream fuse's minimum melting I2t. Figures 22 and 43 show I2t data versus fuse sizes. The ratios of fuse sizes required for coordination are provided in manufacturers' literature in the form of tables showing the size ratio of upstream to downstream fuses that will guarantee coordination. The ratio will be a constant for fuses of the same type (e.g., 2:1), but an upstream fuse of one type may need to be anywhere from 2 times to 8 times the size of a downstream fuse of a different type, in accordance with manufacturers' ratio data. If closer fuse sizing (than indicated by the ratio tables) is desired for a system coordination study, then the other fuse data discussed above should be used. Peak let-through fuse data can be used to coordinate an upstream instantaneous relay with a downstream current limiting fuse. Coordination is achieved if the fuse's peak let-through current times 0.707 is less than the rms pick-up setting of the upstream instantaneous unit. This current limitation effectively ensures that the instantaneous device does not see enough energy to operate. Figure 23 illustrates the half cycle worth of energy it takes to just cause pickup of an instantaneous relay. Figure 24 illustrates the pickup-energy portion of a current higher than the relay's pickup current. It can be seen in Figure 25 that a current-limiting fuse will not allow the relay to see enough energy to pick up if the peak let-through of the fuse is less than the peak of the relay's rms pickup. Peak let-through data is presented as a function of the available symmetrical rms short-circuit current as shown in Figure 26. The line AB in Figure 26 represents the boundary between current limitation and non current limitation. The slope of line AB could be anything from 1.414, which is the peak of a symmetrical current, up to 2.828, which is the peak of a fully offset current. For peak let-through determination, the slope of line AB is a function of the fault power factor, and is often drawn with a slope of about 2.6. A second line AB with a slope of 1.414 can be drawn for a short cut determination of the symmetrical rms current that has the same peak value as the fuse's peak let-through. For example, if for a given situation, the peak let-through current is 14,140 amperes on the y-axis, the corresponding “equivalent" symmetrical rms value per the 1.414-sloped line is 10,000 amperes on the x-axis.

This information is considered CONFIDENTIAL and shall not be released to or discussed with any persons except (a) employees of ExxonMobil Affiliates who have an appropriate research agreement with ExxonMobil Research and Engineering Company (EMRE), and (b) consultants, contractors, or employees of third parties with whom proper secrecy agreements have been executed with EMRE or such ExxonMobil Affiliates. ExxonMobil Research and Engineering Company

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Explosive fuses are current limiting fuses that achieve fault-current interruption with the help of electronically-triggered explosive charges. Such fuses (sometimes called smart fuses) are used where fault current limitation is required, but where the normal operating current is too high for conventional current-limiting fuses. Explosive fuses can be used to split a system with inadequately rated interrupting equipment into two lower fault-level systems, or to limit the fault current from a specific source by opening its circuit or by opening a bypass around a current-limiting reactor. Such applications may be considered when a system is expanded beyond its equipment fault rating and the addition of current limiting reactors would present unacceptable operating voltage problems. Some fuses have indicators that make it easy to detect a “blown" fuse, and striker pins that are released when the fuse “blows". Striker pins are used to trigger a mechanism that opens a switching device to isolate all three phases, thereby preventing single phasing. The rating of a fuse is the current that it can carry continuously without deterioration. However, transient currents and temperature cycling can “age" a fuse; therefore some manufacturers recommend periodic replacement (every five or ten years) to avoid maloperation. The current at which a fuse will start to melt is in the order of 120% to 150% of its rating. A list of I.EC. recommended fuse ratings for low voltage is given in Table 1. For our purposes, fuses can be divided into three main categories, as follows: CATEGORY

TYPICAL APPLICATION

CURRENT LET-THRU

Slow Blow

Rural Distribution Overhead Lines

System Peak

General Purpose

Industry (90% of all fuses)

Current Limiting

Ultra Rapid

Inverter Loads/Instruments

Current Limiting

The operation of a current limiting fuse in its current-limiting zone is shown in Figure 2 where the actual peak current that flows (let-through) is considerably less than what would have flowed if it had not been interrupted by the fuse. Fuse manufacturers provide peak let-through curves which show peak current as a function of fuse size and available fault current. Fuses have many sophisticated features to cater for transformer inrush, motor starting, etc., so much so that in every case for the final design, the manufacture's recommendations should be followed as to which type of fuse is used. Additionally, the data for the actual fuses used should be available for the relay coordination study. In summary, always use the manufacturer's recommendations in selecting the type of fuse, and for relay coordination use the data pertaining to the particular fuse that is used. The following data are generally required from the manufacturer:

5.3

·

Pre-arcing (minimum melting) curves - to discriminate with motor starting and transformer inrush currents, and with downstream overcurrent devices for a fault current below the fuse's current-limiting threshold.

·

Total clearing curves - to discriminate with upstream time-delayed overcurrent devices (not including current-limiting fuses).

·

Peak let-through curves - to discriminate with instantaneous relays.

·

Current squared time (I2t) curves for pre-arcing and total clearing, or fuse selectivity-ratio data, to discriminate between fuses. RELAYS - GENERAL

Protective relays use inputs of current or voltage, or a combination of both, and compare these inputs to a threshold quantity which is normally called the pickup (or the setting). Once the threshold is passed in the operating direction (e.g., high current, low voltage, low fault-impedance, etc.), the relay will either operate almost immediately (instantaneous relaying), or with a time delay. The time delay is either fixed (definite time), or is a inverse function of the measured quantity; e.g., for an overcurrent relay, the higher the current, the shorter the time delay. If the magnitude of the measured quantity returns to a non-operating level before the timing has gone too far, the relay will reset without operating. In addition to measurement, comparison and time delay, some protective relays determine and act upon the direction of the measured quantity; some perform filtering functions such as deriving sequence network quantities; and some can retain event information and perform self-checking. Electromechanical relays use magnetic attraction, magnetic induction, or thermal heating to achieve operation. This information is considered CONFIDENTIAL and shall not be released to or discussed with any persons except (a) employees of ExxonMobil Affiliates who have an appropriate research agreement with ExxonMobil Research and Engineering Company (EMRE), and (b) consultants, contractors, or employees of third parties with whom proper secrecy agreements have been executed with EMRE or such ExxonMobil Affiliates. ExxonMobil Research and Engineering Company

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Solid state relays use low-power resistors, capacitors, and semi-conductor devices arranged into logic circuits to achieve operation. Microprocessor-based relays use digital sampling and processing technology to achieve operation. They can also store event information, do self-checking, and can communicate with external digital equipment. ç

Solid state and microprocessor-based relays have many advantages over electromechanical relays, and have become the relay-type of choice, especially for applications outside of small low-voltage-motor starters. 5.4

MICROPROCESSOR-BASED RELAYS

In recent years, there has been an increasing trend toward the use of microprocessor-based relays. Some of the reasons for the shift from electro-mechanical relays to microprocessor based relays includes:

ç

ç

·

Microprocessor-based relays are more accurate and more repeatable than equivalent electro-mechanical relays.

·

Equivalent functions can be obtained at lower cost because a single microprocessor-based relay can perform the functions of many electro-mechanical relays. Because one device is replacing several, installation costs are greatly reduced, particularly if reduced space requirements result in fewer panels.

·

Some functions, operating characteristics, or communication capabilities which are not possible with electromechanical relays can be done with microprocessor-based relays.

Despite these advantages, microprocessor-based relays raise a number of concerns. The main one is the possibility of total failure of the protective system due to failure of one component on the critical path, such as the power supply. Previously, failure of one discrete relay resulted in loss of only one protection function on one phase. The remaining protection functions on the faulted phase and all the protection functions on the other two phases still provided protection. With the multi-function microprocessor-based relay, a common mode failure can result in the loss of all the protection functions on all three phases. The counter argument is that microprocessor-based relays have diagnostics that provide an alarm if there is a malfunction. With electro-mechanical relays, a malfunction is not discovered until the relay is required to operate. To overcome this concern, a second multi-function relay is sometimes provided for redundancy for large critical equipment such as generators and main transformers. Generally, the second relay would be from a different manufacturer to preclude the possibility of a common mode failure. Adding a second relay doubles the probability of a false trip. As long as backup relaying exists, a 2oo2 tripping connection, with the watchdog contact bypassing the failed relay's trip contact, is a more secure alternative than 1oo2 tripping. Another option is to divide various protection functions into two or more relays. For example, the differential protection for a generator may be housed in an independent relay separate from the other protection functions; i.e., overcurrent, under voltage, loss of excitation, etc. Another problem that has surfaced with microprocessor-based relays is that the complexity of setting these relays has resulted in incorrect settings. The instruction manual for an electro-mechanical relay is in the order of 10-15 pages while the instruction manual for a multi-function microprocessor based relay are usually more than 200 pages. These manuals can be difficult to read and sometimes the instructions are confusing. In some cases, it is difficult to determine the factory default settings. Extra care is required in determining the required settings and transmitting the information to field personnel who will do the setting and testing of the relays.

ç

Other recommendations when applying microprocessor-based relays includes the following:

·

Be sure that the relay watchdog timer contact sends an alarm signal to the substation alarm panel to warn of relay failure.

·

Use only the relay protection functions that are needed. Do not use all the functions included with the relay just because they are available. Be sure the unneeded functions have been disabled by indicating this on the setting sheets and confirming with a printout from the relay. A computer file of the relay's settings is recommended when the total amount of data to be entered into the relay exceeds 1 full page - this avoids errors associated with manual data entry.

·

Understand, define and set up the diagnostic and fault recording information available in the relay.

·

The substation battery supply needs to have filters to insure that if the battery is disconnected for any reason, the ripple on the rectifier output does not damage the relays.

This information is considered CONFIDENTIAL and shall not be released to or discussed with any persons except (a) employees of ExxonMobil Affiliates who have an appropriate research agreement with ExxonMobil Research and Engineering Company (EMRE), and (b) consultants, contractors, or employees of third parties with whom proper secrecy agreements have been executed with EMRE or such ExxonMobil Affiliates. ExxonMobil Research and Engineering Company

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·

Particular attention must be paid to grounding and paths for transient voltages/currents to these relays such as through RTD or DC power supplies. Manufacturer's grounding and isolation recommendations should be carefully followed.

·

Institute a "management of change" procedure to handle changes to relay parameter settings. Document the reason why the change is being made. Record (or download) as-found settings before making the change and document any discrepancy between the found setting and the expected one.

·

Develop a logic diagram (Figure 46) which will be kept in the permanent settings files representing the interaction between the relay's measurement units, digital inputs and the trip/alarm outputs.

·

Documentation of microprocessor relay settings requires special forms (unlike the form shown in Figure 31) due to the number of parameters involved. Computer disk copies of settings should be used to minimze errors resulting from manual data entry. The user must develop a long term file retention system for this critical documentation.

·

Record the firmware revision of every relay as part of the settings sheet. Upgrade firmware only when necessary. Repeat relay commissioning tests when upgrading firmware to be sure the existing settings are compatible with the new firmware.

·

Generate a hard copy of any programmed logic inside the relay and add to switchgear wiring diagrams. The relay should not be a "black box" on the switchgear diagrams. RELAYS - DEVICE DESCRIPTIONS

Most of the relays we use in our plants are discussed below. 5.6

TIME DELAY RELAYS (2) AND (62)

We use time delay relays extensively in protective relaying and in motor reacceleration circuits. These are relatively simple relays with some form of timing device which delays contact operation when the relay is activated. The relays must ensure that the timer can remain dormant for long periods and then operate correctly when required. Timers are either pneumatic, mechanical, or solid state. 5.7

DISTANCE RELAYS (21)

Relays that measure some form of impedance, often along a transmission line, are called distance relays. The terminology for distance relays depends on how the relay uses its current and voltage inputs. Relays that effectively operate on the magnitude of a measured impedance, but not its direction, are called impedance relays; while relays that operate on the magnitude of reactance are called reactance relays. Both of these are normally supervised by a directional relay. Relays that measure impedance magnitude but are inherently directional are called admittance or mho relays. How the current and voltage transformers should be connected for various applications, and how to interpret what each relay sees for unbalanced faults is beyond the scope of this Design Practice. The relay instruction manual should be consulted for any given application. When the measured impedance is less than the preset value, the relay operates. The main applications are on utility networks where they may be the most common relay in use. Some knowledge of their modes of operation is essential to us when we must coordinate our protective relaying with that of the local utility to which we are connected. We have the potential to use distance relaying instead of 51V relaying for generators that are stepped up directly to a utility transmission line protected by distance relaying. An application of distance/impedance relaying is shown in Figure 19 which shows diagrammatically the operating zones and times for one relay on a utility transmission or distribution network. Each of the other circuit breakers shown in Figure 19 will have a similar relay “looking" into its line (i.e., away from its local busbar) with settings on the same basis as the one shown. The first stage of protection “looks" at 80% of its line and for a fault in that zone will operate within 0.1 seconds. The second stage looks at 120% of its line and will operate in 0.5 seconds. The third stage (which may be non-directional) is looking at 200% of the line impedance in both directions and has an operating time of 1.5 seconds. At Busbar B there will be a directional relay on the line between bus A and B looking back towards bus A.

This information is considered CONFIDENTIAL and shall not be released to or discussed with any persons except (a) employees of ExxonMobil Affiliates who have an appropriate research agreement with ExxonMobil Research and Engineering Company (EMRE), and (b) consultants, contractors, or employees of third parties with whom proper secrecy agreements have been executed with EMRE or such ExxonMobil Affiliates. ExxonMobil Research and Engineering Company

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This is only a typical scheme; actual applications will vary considerably. For a fault in the middle 40% of any line, the breakers at both ends will be tripped by the first stage of the protection to isolate the fault. For a fault in the 20% at either end of the line, the circuit breaker nearest the fault will be tripped by the first stage of protection and the circuit breaker at the end of the line farthest from the fault will be tripped by the second stage of protection. If the circuit breaker nearest the fault fails to trip, its busbar will be isolated by the second stage of the feeder breakers supplying the bus. Likewise, the third stage of protection provides back-up protection for a breaker that fails to clear a fault at the remote end of the line. If supply to our facilities is derived from Busbar A, we know that we can see a reduced voltage for 0.5 seconds plus breaker clearing time for distant faults cleared by the second stage of the first line protection. When a line segment protected by a distance relay has a second source of fault current connected between the relay and a fault, the impedance relay sees a higher apparent impedance than when the second source is disconnected. A diagram and formula (Equation 12) for the higher apparent impedance is presented near the end of this Design Practice in the section entitled CONVERSIONS AND CALCULATIONS under the side heading Determining Distance Relay Apparent Impedance, ZR, Due to Infeed Current. An impedance relay that should not see beyond a given distance must be set with the second source disconnected. The relay will not protect as much of the line with the second source in, as it does when the second source is out. In effect the relay underreaches its setting when the second fault-current source is connected. 5.8

VOLTS / HERTZ RELAYING (24) - OVEREXCITATION PROTECTION

Overexcitation (and overheating) of the magnetic core of generators and fully loaded transformers begins when the ratio of per unit voltage to per unit frequency exceeds 1.05, and increases rapidly as the volts/hertz ratio increases. Some form of volts/hertz protection is needed for generators - either in the form of a volts/hertz limiter in the exciter control system or volts/hertz relaying, or both. Volts/hertz relaying is needed for transformers that could be subjected to overexcitation. Where volts/hertz relaying is applied, an alarm function should be provided with enough lead time to allow operator intervention before tripping occurs. 5.9

SYNCHRONIZING RELAYS (25)

Synchronizing relays can be divided into two main groups: system synchronizing check relays, and generator synchronizing relays. The former are used to block paralleling two parts of an electrical system that are not synchronized. They are relatively slow speed and are not used for generator synchronizing on machines above about 500 kVA. Generator synchronizing relays are the main component of equipment packages which function to insure that the system and incoming machine-voltage magnitude, phase angle and slip frequency are within acceptable limits relative to the system voltage at the moment the generator breaker closes to synchronize the machine to the system. Generator synchronizing relays can be further divided into three types:

·

Machine out of synchronism blocking relays

·

Semi-automatic synchronizing relays

·

Automatic synchronizing relays

Machine out of synchronism blocking relays will prevent closing of a generator breaker when the machine voltage vector is outside the preset limits, as compared to the system voltage vector. This relay is more complex than the system synchronizing check relay, since it takes into account the velocity of the machine voltage vector (phase angle and slip frequency) with respect to the system vector as one does when synchronizing manually. Automatic synchronizing relays are equipment packages which adjust the driver governor and generator excitation, and close the generator breaker when the generator voltage matches the system voltage within acceptable limits. Some automatic synchronizing relays are also equipped to load the generator after synchronizing. Semi-automatic synchronizing relays require the operator to close the breaker using the control switch. We use all four types of synchronizing relays. The system synchronizing check relays are used in the automatic transfer circuit (see GP 16-12-02) to prevent an operator from paralleling two infeeds that are out of synchronism when making a manual transfer. Also, we usually use one of the three machine synchronizing relays on our generators to facilitate proper synchronizing and avoid operator errors, even though synchronizing a generator can be done manually using the synchroscope and voltmeters which are always provided.

This information is considered CONFIDENTIAL and shall not be released to or discussed with any persons except (a) employees of ExxonMobil Affiliates who have an appropriate research agreement with ExxonMobil Research and Engineering Company (EMRE), and (b) consultants, contractors, or employees of third parties with whom proper secrecy agreements have been executed with EMRE or such ExxonMobil Affiliates. ExxonMobil Research and Engineering Company

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PROTECTIVE RELAYING

October, 2004

TEMPERATURE RELAYS (26)

These relays are temperature measuring devices with contacts that operate when a preset temperature is reached. We fit these to all our power transformers (see GP 16-10-01) where the relay takes the form of a dial-type thermometer for indicating the top of the liquid temperature. The relay has two hands, one showing oil temperature at time of reading and the second showing maximum temperature reached since last resetting. For our applications, the thermometer must have hermetically-sealed, normally-closed alarm contacts set to open at the maximum self-cooled operating temperature of the transformer. Transformers are normally supplied with temperature relays but the contacts are usually open to the atmosphere. Manufacturers generally meet our requirements by fitting mercury bottle switches. The hermetically sealed contacts are required for two reasons:

·

Transformers are usually located at the very edge of Division 2 areas.

·

Bare contacts that will normally never operate can deteriorate in our plants.

On large main substation transformers, a more sophisticated temperature relay is used that more closely reproduces the hotspot temperature, and switches fans and sometimes an oil circulating pump on and off. 5.11

UNDERVOLTAGE RELAYS (27)

These are either induction disc, attracted armature, or solid state devices that operate when the voltage falls below a preset level. They may be instantaneous, definite time, or time delayed with an inverse characteristic that provides the fastest clearing at zero voltage. The symbol “27" is generally used for time delay relays and “27I" for instantaneous relays. We use undervoltage relays for:

5.12

·

Automatic transfer circuit in GP 16-12-02.

·

Undervoltage protection (tripping) for motors controlled by circuit breakers, latched contactors, and d-c held contactors.

·

Monitoring the voltages of the d-c control power supply for the switchgear plus the control voltage in each switchgear assembly, as per GP 16-02-01 and GP 16-12-01.

·

Step reacceleration circuits.

·

Separation of in-plant generators from the utility (sometimes in combination with a second relay, such as a directional overcurrent).

· ·

To off-load constant torque equipment such as positive-displacement/reciprocating compressors.

·

To protect against a sustained undervoltage on the utility system that cannot be made up by transformer LTC action. This not commonly done but may be required at some locations. It is preferable to trip the incoming breaker before motors begin to trip and lock out due to overloading/overheating.

·

To prevent damage from utility three-phase automatic reclosing where the reclosing involves a time delay that could damage rotating equipment (i.e., too long for ride-through and too short for individual motor undervoltage tripping).

To monitor voltage on each remote bus supplying Emergency Block Valves (EBV's) Type C and D (GP 16-02-01).

DIRECTIONAL POWER RELAY (32)

See DIRECTIONAL OVERCURRENT AND POWER RELAYS (67 AND 32) below. 5.13

LOSS OF FIELD RELAYS (40)

Synchronous generators and synchronous motors are fitted with this relay, which typically uses one or two distance relays, and may include directional and undervoltage units. Loss of field can cause high currents in both the stator and rotor which can lead to dangerous overheating in a very short time. The var drain on the rest of the system can result in low system voltage and can adversely affect system stability. See DP XXX-B.

This information is considered CONFIDENTIAL and shall not be released to or discussed with any persons except (a) employees of ExxonMobil Affiliates who have an appropriate research agreement with ExxonMobil Research and Engineering Company (EMRE), and (b) consultants, contractors, or employees of third parties with whom proper secrecy agreements have been executed with EMRE or such ExxonMobil Affiliates. ExxonMobil Research and Engineering Company

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For salient-pole generators that may operate at low output levels; e.g., backpressure steam regulation, a separate field failure relay should be provided in addition to the normal 40 relay. This is because, at low driving torque levels, the machine may lose synchronism but not activate the conventional loss-of-field relay, yet still be damaged by overheating. The field failure relay monitors the applied field voltage, in addition to other parameters. 5.14

NEGATIVE-SEQUENCE OVERCURRENT RELAYS (46) - GENERATOR PROTECTION

Device number 46 is used both for Phase Balance relays, which respond to unbalanced phase currents, and for Negative Sequence current relays, which respond to the negative sequence component of unbalanced phase currents. The negative sequence type is more sophisticated and thus provides better protection with less false tripping than the unbalance type. It is our normal practice to provide Negative Sequence Current (46) relaying to generators, and to trip the generator breaker with this relay. The application of Phase Balance relaying is covered under the next subheading below. Negative sequence currents are caused by system imbalances and asymmetries such as unbalanced faults, untransposed transmission lines, an open-circuited phase, and unbalanced load. Negative sequence currents in a machine stator induce double-frequency rotor currents, which produce additional heating that can be damaging even when the total phase current is less than rated current. Even a small voltage unbalance can produce significant negative-sequence current because the negative-sequence impedance is relatively low - approximately equal to the subtransient reactance for a generator (or the locked rotor impedance for a motor). Thus a 5% negative sequence voltage applied to a generator with X2 = 12.5% can produce I2 = 40% of generator rated current, which would quickly cause an excessive temperature rise. Generators have a short-time negative-sequence-current limit expressed as I22t = K, where K is, for example, 30 for an aircooled cylindrical rotor machine (per MG-1). Generators have a continuous I2 capability limit which is typically 10 percent of the rated phase current (per MG-1), and may be as high as 15% in some machines. Electromechanical negative-sequence current relays have an extremely inverse I2 versus time characteristic which generally cannot be set more sensitively than to pickup at about I2 = 60% of rated full load current; therefore their primary tripping function is to protect the generator against an uncleared phase-to-phase fault. It is herein recommended that solid state negative-sequence current relays be used for generator protection because they provide more sensitive protection than electromechanical relays. Solid state 46 relays typically can protect generators against I2 currents almost as low as the generator's continuous I2 capability. For example, if a relay has a maximum delay of 990 seconds, and K is 30, the relay will correctly trip for I2 down to 17.5% of generator rated current. It is herein recommended that consideration be given to a 46 relay with the additional feature of a sensitive alarm setting (with a small alarm delay of about 5 seconds) which can warn the operator that a low level unbalance problem is developing. This may give the operator sufficient time to take prescribed actions, which could include separating from the utility if the utility is identified as the source of the imbalance; or determining the amount of imbalance and, if practical, reducing generator output to reduce machine temperature. Any of these actions would have to be pre-planned and documented as operating procedures. Each application of a 46 relay has to be evaluated on its own merits. In some cases it may be preferable to immediately trip the generator breaker at the first sign of trouble because the utility can handle the load. In another situation, the in-plant generation may provide most of the power and it may be preferable to drop a weak utility tie - especially since it may well be the utility that is causing the imbalance. 5.15

PHASE BALANCE RELAYS (46) - MOTOR PROTECTION

Phase balance relays have typically only been applied to motors when this protection function is included as part of a comprehensive solid-state motor-protection relay. It is not required by ExxonMobil's Global Practices. However, where large unspared critical motors are involved, it is recommended to consider phase balance relaying, which can be provided by a comprehensive solid-state motor-protection relay.

This information is considered CONFIDENTIAL and shall not be released to or discussed with any persons except (a) employees of ExxonMobil Affiliates who have an appropriate research agreement with ExxonMobil Research and Engineering Company (EMRE), and (b) consultants, contractors, or employees of third parties with whom proper secrecy agreements have been executed with EMRE or such ExxonMobil Affiliates. ExxonMobil Research and Engineering Company

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5.16

ELECTRICAL POWER FACILITIES

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NEGATIVE SEQUENCE VOLTAGE RELAYS (47) - MOTOR PROTECTION

This relay is not required by ExxonMobil's Global Practices, and has not previously been covered in this Design Practice. However, it is recommended that negative-sequence-voltage relaying, set to alarm, be considered for the main power buses of all plants. If there is in-plant generation which has tripped due to negative sequence relaying, that relaying is no longer there to indicate whether the negative-sequence condition is persisting and potentially damaging the plant's motors. Per ANSI C37.96, a motor with a typical 0.167 per unit locked rotor impedance, when subjected to a 5% negative sequence voltage, will experience a 30% negative sequence current and a 40 to 50% increase in temperature rise. Since this temperature rise is originating in the rotor, it will not be sensed by overload relays and probably would not be sensed by stator RTD's until it is too late. A 47 relay is sensitive to imbalances in the source system upstream of the relay, but is much less sensitive to downstream imbalances because downstream imbalances generally have a minor effect on the upstream voltage that the 47 relay is sensing. A 47 relay applied on a plant's main power busses is likely to detect an open phase or other imbalances in the utility system, but not an open phase in an in-plant distribution feeder. Since our in-plant designs make it unlikely that we will have an open phase or other persistent imbalance inside the plant, we could apply 47 relaying on our main power buses to detect and alarm for the presence of negative sequence voltage arising from the utility company's system. 5.17

THERMAL OVERLOAD RELAYS (49) AND LOCKED ROTOR PROTECTION

In IEEE standards, device “49" is listed as a “Thermal Relay" which functions when a winding temperature exceeds a preset value. In practice, most motor overload devices in our plants do not sense winding temperature, but instead, they use stator current to simulate thermal conditions in the motor. In some cases, current-sensing overload relays are supplemented by winding temperature detectors which provide a high-temperature alarm. As used herein, the term “thermal relays" is applied both to separate relays supplied from external current transformers and to the thermal elements (sometimes called “heaters") in motor starters. As discussed below, a 49 relay may also be used to provide motor locked-rotor protection. With few exceptions (discussed below), our motors are tripped for specified overload conditions via solid-state or thermalelement relays that monitor all three of the stator phase currents. Our practices do not call for tripping of motors via winding temperature detectors, which activate alarms upon sensing high stator temperature. Thermal overload relays are normally set to pick up at 110 to 115% of motor full load amperes (FLA) for 1.0 service factor motors, and at 125% of FLA for 1.15 service factor motors. These settings provide protection against moderate overloads. Higher settings - up to 140% of FLA per discussion below - might be approved on an exception basis when normal settings trip the motor on starting, or when critical process considerations make it worth subjecting a motor to moderate overload rather than tripping it. The role of thermal overload relays in locked rotor protection will now be addressed. Thermal overload relays protecting medium-voltage motors have to be supplemented by a separate overcurrent (51) locked-rotor relay in one phase. See Figures 28 F and G. Two things to keep in mind in the application of locked-rotor-current sensing devices are as follows:

·

They may operate even though the applicable relay curve is above the trace of the starting current. This can happen because the relay integrates the effect of the current. Thus the relay curve either has to be set above the motor's total starting time (assuming constant locked rotor current), or the integration effect of the relay has to be taken into account (which is somewhat complicated, and will not be addressed herein).

·

In some cases, it may not be possible for a locked rotor relay to both start/reaccelerate a motor and provide locked rotor protection because the motor starting time exceeds or is too close to the locked rotor damage time. In such cases one of the two options discussed at the end what follows has to be implemented.

Locked rotor protection for contactor-controlled, low-voltage motors is provided solely by the contactor's standard overload relays when the relay characteristic provides both locked-rotor protection and starting/reaccelerating capability. However, if they cannot be set to both prevent locked rotor damage and allow the motor to start (or reaccelerate), the following solutions should be evaluated:

·

If the motor can be started/reaccelerated, but the overload relay does not provide locked rotor protection, add a separate locked rotor relay if it can be set above the motor starting time and below the locked rotor damage point.

This information is considered CONFIDENTIAL and shall not be released to or discussed with any persons except (a) employees of ExxonMobil Affiliates who have an appropriate research agreement with ExxonMobil Research and Engineering Company (EMRE), and (b) consultants, contractors, or employees of third parties with whom proper secrecy agreements have been executed with EMRE or such ExxonMobil Affiliates. ExxonMobil Research and Engineering Company

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·

If the motor cannot be started/reaccelerated because the starting time is too long for the standard (Class 10) thermal characteristic (cold curve for starting, hot for reaccelerating), investigate substituting an overload relay with normal pickup setting and a longer time delay at lock rotor current (e.g., a Class 20 or 30 overload relay). If the longer delay allows starting/reacceleration but it does not provide locked rotor protection, add a separate locked rotor relay that permits starting and provides locked rotor protection.

·

If the motor still cannot be started using longer delay characteristics per above, change to the next size thermal element or increase the relay pickup so that the motor can start (or reaccelerate). This solution does not provide protection against moderate overloads. In no case shall the pickup exceed 140% of motor FLA. If pickup would have to exceed 140% of motor FLA to permit starting/reacceleration, the overload must be replaced with one that picks up below 140%. With pickup not exceeding 140% of motor FLA, and with the motor able to start/reaccelerate, the overload relay must either protect against locked-rotor damage, or it must be supplemented by a separate locked rotor relay.

If a motor's starting time exceeds or is too close to the locked rotor damage time, simple locked rotor protection will not work properly. In this case, thermal overload relays provide protection against moderate overloads, and a separate locked-rotor relay must be provided with supervision per one of the following:

·

Use a “zero-speed" switch to supervise a locked rotor relay set to protect the motor against locked rotor damage. The switch disables the relay trip signal if the motor achieves a preset low-level speed soon after the motor is energized.

·

Use a distance (mho) relay to supervise a locked rotor relay set to protect against locked rotor damage. The distance relay (21) operates immediately when it sees a locked rotor impedance, and closes its contact which is in series with the contact of the locked rotor relay. If the 21 relay continues to sense a locked rotor condition, the locked rotor relay will trip the motor when it finishes timing out. However, if the motor impedance changes sufficiently to indicate that a successful start is underway, the 21 relay drops out and disables the trip signal from the locked rotor relay. Check with the relay vendor to determine if it is preferable to use a three phase distance relay over a single phase relay for this application.

If it is specified that a piece of driven equipment is so critical to the process that it is preferable to sustain moderate insulation aging/damage than to trip for a moderate overload, the overload relays shall be set higher, and shall be supplemented by winding temperature detectors (or less preferably by an additional thermal-overload relay) set to alarm at or just above motor rating. The alarm has to sound in a manned control room so that immediate attention can be paid to the situation. The normal overload relays would be set to trip above any foreseeable overload (such as a surge condition in a compressor) but not above 140% of motor FLA. If the critical motor is a low voltage motor and is not protected against locked rotor by the “tripping" overload relays, a separate locked rotor relay must be provided. The locked-rotor function of a multi-purpose motor-protection relay can be used in place of a separate locked rotor relay if its range and adjustability provide proper protection. The locked rotor protection functions of some multi-purpose relays have limited adjustability and are tied to both the hot and cold thermal curves, thus potentially creating difficulty in fitting the relay characteristic between the motor start time and the locked rotor damage point(s). If the locked rotor function does not have its own output contact, it could not be used with the speed switch or distance relaying schemes above. The additions and exceptions to tripping of motors via current-sensing thermal-overload relays in all three phases are as follows:

·

Thermal overload relays are disconnected for Type C and D Emergency Block Valves (per GP 16-02-01), and thermal overload relays are not provided in the starters for firewater pumps. The basis for omitting overload protection is that the risk to people would be greater if the motor is tripped on overload than if it is not.

·

When low voltage motors are controlled by switchgear circuit breakers with direct acting trips, the direct acting trips provide overload and locked rotor protection, with backup via an overload relay in one phase.

·

Motors with air filters and motors over 1500 HP are to be provided with the additional protection of a high temperature alarm from resistance temperature detectors imbedded in the stator winding. The alarm level should be at or just above the rated temperature of the winding. Overload and locked rotor protection are provided by relays per normal practice discussed above.

This information is considered CONFIDENTIAL and shall not be released to or discussed with any persons except (a) employees of ExxonMobil Affiliates who have an appropriate research agreement with ExxonMobil Research and Engineering Company (EMRE), and (b) consultants, contractors, or employees of third parties with whom proper secrecy agreements have been executed with EMRE or such ExxonMobil Affiliates. ExxonMobil Research and Engineering Company

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INSTANTANEOUS OVERCURRENT RELAYS (50)

Instantaneous overcurrent relays (50) are electromechanical or solid-state relays with very short operating times - on the order of one-half to one cycle at or above 5 times pickup, and about 1.5 cycles at 1.5 to 2 times pickup. Below 1.5 to 2 times pickup, relay operating time may be 2 to 5 cycles or more. Thus instantaneous relays are not truly instantaneous. See Figure 7. Some instantaneous relays have low overreach (see DEFINITIONS section) because of dc filters, and therefore they see much less current than may actually be flowing in an offset fault current. See Figures 3, 4, and 5. Low overreach allows these relays to be set lower than high overreach relays, thus providing more sensitive protection. See Figure 6 for typical overreach data on a low overreach 50 relay. In summary, instantaneous overcurrent relays:

5.19

·

Are calibrated in symmetrical rms amperes.

· ·

Pick up at a current equal to the setting value.

·

Some are available with d-c filters to reduce transient overreach to much lower values than unfiltered relays.

·

Vary in performance. Manufacturer's data of actual relay should be used.

Have very rough rule of thumb operating times of one and a half cycles at a current equal to 1.5 times the setting, and half to one cycle at a current equal to five times setting.

INVERSE TIME OVERCURRENT RELAYS (51)

These relays either have an induction disk that rotates when the current is above the setting to close a set of contacts, or are electronic solid state devices. The role of 51 relays in motor locked-rotor protection is discussed above under THERMAL OVERLOAD RELAYS (49) AND LOCKED ROTOR PROTECTION. Facilities are provided to adjust both the current setting and the time of operation to give a family of curves for time vs. current. In the case of electromechanical relays, the current is adjusted in steps by inserting a plug into a socket that usually has a current range of four to one times nominal current in seven steps. The time is adjusted by a dial that varies the angular distance through which the disk has to rotate to close the contacts. This “time dial" is infinitely variable over a range of settings. Typical setting ranges are 0.5 to 10, 0.1 to 1. A typical family of curves for an inverse time induction-disk overcurrent relay is shown in Figure 8. A typical solid-state relay has a current range of 2.4 to 0.05 times nominal current in 47 steps. Its time characteristic can be varied from 0.05 to 1.0 times the time of the base characteristic (in steps of 0.025). For the inverse time characteristic, this results in a range from 0.1 second to 2.0 seconds at 31 times the current setting, in steps of 0.05 second. This is comparable to the time range of the induction-disk relay in Figure 8. It will be noted in Figure 8 that the curves are not extended below a current of one and a half times the tap (current) setting. In theory, the relay should pick up at the current setting of the tap selected but, in fact, the induction disc generally starts to rotate (pick up) at a current slightly above the tap setting. Thus, the relay's accuracy in the region of the pickup current is not reliable. One solid-state-relay manufacturer shows the relay curves dashed below 2 times pickup and gives accuracy data only above 2 times pickup. At high multiples of the pickup setting, varying from 20 to 50 times pickup, depending on the relay, the Time vs. Current curves of inverse relays tend to go asymptotic. Because of this, many inverse time relays are designated as Inverse Definite Minimum Time (IDMT), with a specified minimum time of operation at the point where the Time vs. Current curve becomes asymptotic at high currents. This time is useful when determining time dial settings to provide discrimination between relays. Relays are available with varying degrees of Time vs. Current slope to suit the various applications. The normal classifications are “Extremely Inverse," “Very Inverse," and “Inverse," as shown in Figure 9. Extremely inverse relays are useful in providing discrimination with fuses, as the shapes of the two Time vs. Current curves are similar. Where coordination with fuses is not a problem, an inverse-time characteristic provides a relatively short operating time over a wide range of currents, and is the curve of choice in the majority of applications.

This information is considered CONFIDENTIAL and shall not be released to or discussed with any persons except (a) employees of ExxonMobil Affiliates who have an appropriate research agreement with ExxonMobil Research and Engineering Company (EMRE), and (b) consultants, contractors, or employees of third parties with whom proper secrecy agreements have been executed with EMRE or such ExxonMobil Affiliates. ExxonMobil Research and Engineering Company

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Extremely inverse relays should not be used for transformer primary protection as they are not suited to the large range of currents over which selectivity is required. Transformer primary protection (51) relays have to see through the transformer for secondary faults. If extremely inverse relays are used for primary protection of transformers, it is generally not possible to meet the GP 16-02-01 requirement of operating in less than two seconds at 50% of minimum secondary bolted phase-to-phase fault current.

One feature of all inverse time overcurrent relays, both induction disk and solid state, is overtravel/overshoot (see DEFINITIONS section) which causes the relay to continue to “time out" for a short time after the current has ceased. For selectivity, it is common to allow 0.05 (solid state) to 0.1 second (induction disk) for overshoot of upstream relays. Use actual relay overshoot data where available. 5.20

DEFINITE TIME OVERCURRENT RELAYS (51)

These relays are an alternative to the inverse time overcurrent relays and are designated by the same number 51. They may be considered as an instantaneous relay (50) plus a timer, thus, it can be seen that their operation occurs after the setting current has been maintained for the duration of the time setting. The Time vs. Current operating curve is shown in Figure 10. Some advantages of Definite Time Overcurrent Relays over Inverse Time Overcurrent relays are:

·

They provide as good (fast) protection at low fault levels as at high levels.

· 1.

They are very easy to apply for discriminating between each other. Disadvantages are:

·

The shape of their Time vs. Current curve is undesirable for discrimination with fuses.

·

The shape of their Time vs. Current curve does not follow the thermal overload characteristics of generators, motors, transformers, etc.

Ideal applications for Definite Time Overcurrent relays are for system fault protection where it is not necessary to coordinate with fuses and the thermal characteristics of equipment. 5.21

VOLTAGE-RESTRAINED (VOLTAGE-CONTROLLED) OVERCURRENT RELAYS (51V)

We use these relays for generator and generator-busbar overcurrent back-up protection (see DP XXX-B). A voltage-restrained relay uses voltage to apply restraint to an overcurrent relay. For example, a 51V relay that picks up at 200 % current when the voltage is 100%, may pick up at 50% current when the voltage is zero. The pickup, and therefore the relay curve, varies continuously with voltage, which makes coordination analysis more complicated than with the voltage-controlled type of relay. A voltage-controlled relay works as follows: when voltage is above the relay's voltage setting, operation of the overcurrent element is blocked or a relatively high pickup characteristic is selected; but when the voltage dips below the relay's setting, a low pickup characteristic is enabled. The voltage setting should be below the lowest expected voltage during motor reacceleration or other stable voltage transient (probably set just below about 60% voltage). We need the increased sensitivity of the 51V for generators under fault conditions because, being backup protection, the relay has a relatively long time delay, and during this delay, the generator fault current will decay significantly from its initial value. Without voltage restraint, an overcurrent characteristic set high enough to avoid tripping for non-fault conditions would take unacceptably long to operate for a decaying fault current, if it operated at all. We put the current transformers (CTs) for the 51V at the neutral end of the generator phase conductors. This location provides backup protection for the generator when the generator is connected to a system that has little or no capability to backfeed fault current into the generator (e.g., island operation). If the potential transformers (PTs) for the relay were on the generator side of the generator circuit breaker, the CTs in the generator neutral leads would provide backup to the generator differential protection when the generator is energized prior to connection to the system. However, we usually use the main bus PTs for the 51V to save the cost of the extra set of PTs that would be required to obtain this infrequently needed protection.

This information is considered CONFIDENTIAL and shall not be released to or discussed with any persons except (a) employees of ExxonMobil Affiliates who have an appropriate research agreement with ExxonMobil Research and Engineering Company (EMRE), and (b) consultants, contractors, or employees of third parties with whom proper secrecy agreements have been executed with EMRE or such ExxonMobil Affiliates. ExxonMobil Research and Engineering Company

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The 51V provides the ultimate backup for an uncleared fault in all parts of the electrical system into which its setting can reach. The 51V has an inverse characteristic, which coordinates well with the inverse characteristics of our in-plant relaying. However, if a generator is stepped up directly to a transmission system protected by distance relays, one would use distance relaying in place of 51V relaying. In this case, attention must be paid to the configuration of the CTs and PTs relative to the winding configuration of the step-up power transformer. Because the generator fault current is decaying with time and the relay is integrating the effect of the current, a relay with an inverse time-current characteristic will operate some time sooner than the time where the trace of the decaying current intersects the relay curve. Thus it is not apparent when relays will operate, and what the discrimination interval between relays will be. The analysis is made more complex if the relay characteristic varies with voltage as it does with the voltage-restrained type of 51V relay. GP 16-02-01 requires a relay coordination study to take account of generator decrement effects on relay operation per the method reported by Arnold Kelly in IEEE Transactions on Industry and General Applications, March/April, 1965, pp. 130-139. Generator decrement varies with loading, exciter response, and electrical distance from the fault. The 51V relay should be set with the minimum safe discrimination interval practical for the maximum fault current through the 51V at zero voltage, and for the least current that would flow simultaneously through the downstream relay. This condition is usually obtained when the generator with the 51V is the only source of fault current. The setting should be checked for proper operation under emergency operation conditions such as motor reacceleration and stable transient swings for which tripping should not occur. If the voltage signal drops to zero, typical 51V settings will result in operation of the relay for generator load currents above about 50% of generator rating. Thus a generator can be tripped off line due to nothing more than a blown PT fuse. To avoid this problem, voltage balance relaying (device 60) or other PT blown fuse protection should be considered (as discussed further below). 5.22

OVERVOLTAGE RELAYS (59)

Overvoltage protection monitoring bus voltage is not normally provided in our systems, but could find application when a generator vendor requires such protection, or where power factor correction capacitors could cause overvoltage at light load. For generators, volts/hertz relaying (device 24) would be the preferred overvoltage protection, if overvoltage protection is to be provided. If device 59 is provided for generator terminal voltage, it would typically be used to alarm, and would be supplied from the relaying PTs, and not from the PTs for the generator's voltage regulator. Device 59 is used to monitor voltage across the resistor of a high resistance grounded system, and alarms or trips depending on operating philosophy. 5.23

VOLTAGE BALANCE RELAY (60) / PT FUSE FAILURE

It is recommended that voltage balance relaying (60) or other PT blown fuse protection be considered to protect against false tripping of a generator due to a blown fuse in the PTs used for 51V relaying (or 40 or 21 relaying). It also protects against false tripping of motors due to misoperation of 27 or 40 relays. The IEEE and GE recommend such protection. It can be provided by a voltage balance relay of the type that connects between two sets of PTs which sense the same voltage, or by the PT fusefailure feature of a digital generator-protection system. This protection should sound an alarm and block tripping by the relays affected by the loss or reduction in voltage. The voltage balance relay should be connected between the PTs for generator relaying and the PTs for the generator's voltage regulator. 5.24

BUCHHOLZ AND SUDDEN PRESSURE RELAYS (63)

If fault pressure protection is applied for oil-filled transformers, it will be rate-of-rise type for sealed tank designs, or Buchholz type where conservator tanks are used. The Buchholz relay is connected in the pipe between the conservator and tank of an oil-filled transformer. It traps bubbles of gas released in the transformer as they travel to the highest point and initiates an alarm to signify an incipient fault. It also trips the transformer circuit breaker(s) if there is an internal fault that causes a surge of oil. There have been reports of false operation of rate-of-rise type relays due to rapid changes in ambient air temperature and due to through faults, with the result that many such relays have been disconnected. Hopefully, the root causes of these false trips will be found, and the relay design will be changed as necessary since this relaying provides for rapid disconnection of transformers under 10 MVA where differential relay protection is not normally provided.

This information is considered CONFIDENTIAL and shall not be released to or discussed with any persons except (a) employees of ExxonMobil Affiliates who have an appropriate research agreement with ExxonMobil Research and Engineering Company (EMRE), and (b) consultants, contractors, or employees of third parties with whom proper secrecy agreements have been executed with EMRE or such ExxonMobil Affiliates. ExxonMobil Research and Engineering Company

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DIRECTIONAL OVERCURRENT AND POWER RELAYS (67 AND 32)

Two types of Directional Relays discussed herein are the directional overcurrent relay (67) and the directional real-power relay (32), both of which sense the magnitude and direction of the measured quantity. In order to do this, the relay requires a polarizing signal (usually voltage) in addition to the current input. Directional relays will operate correctly with a voltage as low as 1% for faults near the relay. When showing these relays on a one-line diagram, an arrow should always be added pointing in the direction that the current (or power) must flow for operation of the relay (i.e., the direction in which the relay is “looking"). Directional Overcurrent (67) relays are required wherever there is a closed loop, such as a spot network substation, to provide selective tripping either as the prime protection or back-up to unit protection. Generally, directional overcurrent relays should not be used to protect a generator cable. It is very difficult to set this relay so that it will provide cable fault protection but not operate for stable system transients which cause reactive current flow into the generator (similar to loss-of-field conditions) but which would not cause field failure relay (40) operation. The generator cable should be protected by the generator differential relay. See Figures 11 and 12. Where circumstances such as distance between the generator and its circuit breaker necessitate use of the directional overcurrent relay as in Figure 11, particular attention must be devoted to selection of the operating characteristics and settings of both the directional overcurrent and field failure relays to minimize the possibilities for the false operation described. The directional or reverse power relay (32) protects against power flow from the system into the generator which occurs on loss of drive motive power. This relay is required for all gas turbine generators due to the substantial power drain from the system required to motor the gas turbine. It may not be required for steam turbine generators (power drain is relatively small) if the turbine has protection and alarm provisions for the motoring condition. Very sensitive reverse power relaying is used at the secondary of an import-only utility-tie transformer to sense the loss of the primary-side voltage when there is a secondary-side voltage source. This is needed when the opening of a remote primary-side circuit breaker does not send a transfer trip signal to the transformer's local circuit breakers. 5.26

FREQUENCY RELAYS (81)

The main applications for these relays are:

· ·

Load shedding To separate in-plant generation from the utility

A more sophisticated variation of this relay measures rate of change of frequency which is often a better yardstick when deciding how stable the system is at any one time (see Subsection B). 5.27

PILOT-WIRE RELAYS (85)

Pilot wire relays are most often used as distribution or transmission line differential relays. When medium and high voltage line differential zone of protection extends over long distances, say in excess of a few hundred feet, a differential pilot wire (85) scheme is generally used. The scheme employs a relay and three CTs at each end, and a pair of pilot wires between the relays to permit comparison, instead of extending all of the current transformer secondary circuits from one end of the zone to the other. See Figures 17 and 18. The outputs of the three current transformers are summed unequally such that a balanced threephase fault produces a net input to the relay. In the case of conventional differential protection, four or six conductors are required to connect the CTs to the three 87 relays. Larger conductor sizes are required as the distance between the two ends of the zone increases. Pilot wire protection only requires one pair of wires between the ends of the zone that can be miles apart. Supervision of the pilot wire circuit is available. Pilot supervision will detect and alarm a short circuit, open circuit, or earth fault on the pilot wires. It is usual for us to apply “pilot supervision" on these pilot wires. The pilot circuit can be provided by fiber optic cables; this is the preferred method when longer distances are involved. Relays are available that are designed for fiber optic interconnection and adapters can be installed to replace existing copper-pair interconnections to eliminate problems with ground potential rise and induced current.

This information is considered CONFIDENTIAL and shall not be released to or discussed with any persons except (a) employees of ExxonMobil Affiliates who have an appropriate research agreement with ExxonMobil Research and Engineering Company (EMRE), and (b) consultants, contractors, or employees of third parties with whom proper secrecy agreements have been executed with EMRE or such ExxonMobil Affiliates. ExxonMobil Research and Engineering Company

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LOCKOUT RELAYS (86)

Sometimes called “master tripping relay." It is an interposing relay in the trip circuit of a circuit breaker which can be initiated by one or several protection relays. When energized, it does three things: 1. Seals in. 2. Trips the protected circuit(s) by sending a trip signal to one or more circuit breaker(s). 3. Isolates the closing circuit of the circuit breaker(s) supplying the protected circuit to prevent either automatic or manual reclosure. Note that the relay should isolate the circuit breaker's closing circuit which is different from maintaining a trip signal. In the former case, the breaker cannot be closed, in the latter, the breaker can be closed but will trip again immediately. Reset of the relay may be electrical or by hand. We always use hand reset. Lockout relays may be series or shunt type. The description of these is given in GP 16-12-02. We use lockout relays with hand reset for:

·

Medium voltage motors, unless the relays for fault protection have mechanical lockout incorporated in them (GP 16-1201).

·

Transformers where we specify transformer protection or transformer secondary protection (GP 16-12-02). When transformer differential protection is applied, the differential, Buchholz (or fault pressure relay) and transformer neutral grounding relay are all required to act through a lockout relay which in turn trips the transformer primary feeder circuit breaker and the main secondary breaker per GP 16-02-01.

·

Generators - operated by all the generator protective relays. We generally use two lockout relays for this duty. One for the generator faults, e.g., differential, and the other for external faults, e.g., 51V.

·

Busbar differential protection.

5.29

DIFFERENTIAL RELAYS (87)

These relays measure the difference between the current entering a part of the network and the current leaving the same part of the network. If there is a discrepancy between these two measurements, there must be a fault, so the relay operates. This is a type of “Unit Protection" or “Zone Protection" as the relay is only looking at one unit of the network (a cable, transformer, motor, generator, or busbar), and if “what comes out" does not equal “what goes in", there is a fault in that unit, so the relay operates “instantaneously" to trip the circuit breaker(s). Examples of differential protection are shown in Figures 13, 14, 15, and 16. Differential protection is more expensive than conventional overcurrent protection but has several distinct advantages:

· ·

Selectivity is not required with other relays. This permits sensitive settings with “instantaneous" operating times. Location of fault is known - it must be in the zone of protection.

We usually apply differential protection to:

·

Main substation power transformers, generator unit-transformers, and all transformers rated 10 MVA and larger.

· ·

Motors rated 2501 HP (1801 kW) and above.

·

Busbars and cables connected to a system that has a generator operating at the same voltage.

·

Main substation busbars.

Generators (except Instrument Power Supply (IPS) generators as these are small).

The selection of high-speed differential protection helps to maintain system stability for plants with in-plant generation. As differential protection is required to operate only for faults within the zone of protection, it must be stable (not operate) for faults that are outside the zone. These “through faults" will cause large currents to flow which will be equal in the input and

This information is considered CONFIDENTIAL and shall not be released to or discussed with any persons except (a) employees of ExxonMobil Affiliates who have an appropriate research agreement with ExxonMobil Research and Engineering Company (EMRE), and (b) consultants, contractors, or employees of third parties with whom proper secrecy agreements have been executed with EMRE or such ExxonMobil Affiliates. ExxonMobil Research and Engineering Company

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output circuits of the differential relay's zone of protection. However, the input and output currents sensed by the differential relay will not be equal due to CT errors, therefore, the relays need to have a “percent bias" to avoid false operation. Such relays are called “percent differential relays". The percent bias is achieved by introducing restraint against relay operation in such a way that there is significant restraint against operation for external faults, and there is virtually no restraint for internal faults. This bias is normally expressed as the ratio of the “erroneous" operating current to the average restraining current. If the actual error current in the operating coil (expressed in percent of the actual restraining current) is less than the relay's percent bias, the relay will not operate for a through fault. The percent bias can be either fixed for all through currents, or variable, with the percent restraint increasing as the through-current (and therefore the current transformer error) increases. Thus if the maximum error expected between the current transformers is 10% for the maximum through fault, a fixed 15% or 20% bias characteristic will prevent false operation. If the error between current transformers could be relatively high at high through-fault currents, the better choice is a variable percent differential relay which varies the operating to restraining ratio from about 5% to 10% at low currents to as high as 60% at high currents. Transformer differential protection is more complex than differential protection for motors, generators, lines and buses because:

·

When the ratio of the current-transformer ratios does not equal the current-ratio of the power transformer, there is an error current to the differential relay operating coil; e.g., a 13.8/4.16 kV transformer has an ampere ratio of about 1:3.3, whereas the associated CTs may be 200/5 and 600/5 (a 1:3 ratio). Thus a through fault gives rise to a guaranteed 10% error current in the operating coil in this example.

·

There is often a phase angle difference between the primary and secondary currents, unless the transformer vector connection is star / star or delta / delta.

·

The ratio of primary to secondary current varies with the transformer tap changer position.

·

There may be large inrush currents when the transformer is energized, giving the appearance of an internal fault.

To overcome the above problems, the transformer differential protection (usually denoted by 87T) is arranged as follows:

5.30

·

If there is a ratio mismatch between the power transformer and current transformers, the differential relay should have adjustable taps to compensate for this ratio mismatch, or auxiliary current transformers with taps need to be interposed to correct the mismatch.

·

To compensate for phase angle difference, the CTs on the transformer delta winding are connected in star, and the CTs on the transformer star winding are connected in delta.

·

To compensate for the variation in the power transformer ratio due to tap changing, transformer differential relays have a larger minimum percentage bias (10 to 40%) to desensitize the relay as compared with a generator differential which has a percentage bias of 5 to 10%.

·

“Harmonic restraint" is built into the relay to prevent false operation when the transformer is energized, or when inrush occurs due to transients such as fault clearing. GP 16-02-01 requires harmonic restraint on all transformer differential relays. GROUND (EARTH FAULT) RELAYS (50N, 50G, 50GS, 51N, 51G, 51GS, 67N)

See DP XXX-D for descriptions of ground fault relay types and applications. They can either be supplied from three CTs connected residually (for which we usually use the symbol “N"), or from a CT in the neutral of a generator or transformer, or from a core balanced CT on a feeder cable. In the two latter cases, we usually use the symbol “G" although, this convention is not universally followed by all vendors in their application literature. Ground fault protection is sometimes provided by phase fault protective devices, such as in the case of out-going feeders on solidly-grounded, low-voltage systems when local regulations permit it and when clearing of arcing ground faults is achieved in under two seconds. Generator phase differential relaying may be sensitive enough to provide first line ground-fault protection for generators. ç

Incorrectly connected, or improperly set, earth fault relays will not be revealed by balanced load currents. Therefore, it is important to confirm their proper operation at commissioning, using primary injection.

This information is considered CONFIDENTIAL and shall not be released to or discussed with any persons except (a) employees of ExxonMobil Affiliates who have an appropriate research agreement with ExxonMobil Research and Engineering Company (EMRE), and (b) consultants, contractors, or employees of third parties with whom proper secrecy agreements have been executed with EMRE or such ExxonMobil Affiliates. ExxonMobil Research and Engineering Company

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CURRENT TRANSFORMERS

Current transformers form a vital part in protective relaying as we depend on them to reduce the large primary currents to manageable levels for the relays. When selecting current transformers for Design Specifications, generally the only parameter specified is the ratio, but the following factors should also be taken into consideration:

·

Number of CTs on a circuit. We do not normally use the same set of CTs for differential relaying, overcurrent relaying, overload relaying, and metering, although technically it is possible. All differential circuits should have their own CTs. Metering and overcurrent relaying are preferred to be on separate CTs. The revenue (custody) metering will always have its own CTs.

·

Burden on the CTs. Even after it has been determined that several sets of CTs are required, there may be too high a burden on one set, although this is very rare and may only present a problem with generator relaying.

·

Auxiliary CT's should be avoided if possible, however, if used, their burden must be added to the total. The burden of relays 'downstream' of the auxiliary CT is multiplied by the square of the auxiliary CT turns ratio.

·

Overlapping zones. Differential circuits and directional relays should be arranged where possible with overlapping zones.

·

Space. Having given all the reasons above for adding current transformers, it must be borne in mind that the space for CTs in equipment generally limits us to two or three sets at the most. More space is unusual.

When purchasing CTs, other factors have to be taken into account, such as:

·

Knee voltage - which must be high enough to drive the relays. Care must be taken with multi-ratio CTs because the accuracy of the CT at the knee point on the lower ratios may not be adequate.

·

Accuracy required for the specific application. Accuracy is measured in terms of ratio error, which is effectively the error between what the secondary current would be based on the turns ratio and what it actually is. This error is expressed as a percent of what the ideal secondary current would be without the error. For CTs for which the accuracy can be calculated (as discussed below), it is reasonable to use the calculated excitation current (divided by the ideal secondary current) as the measure of the error for phase devices. The excitation current is a function of the voltage across the CTs burden, which voltage is calculated when the current through the burden is the largest current for which operation is desired. This is usually the maximum three-phase short circuit current reflected through the CT turns ratio. Some text books indicate that when an instantaneous relay (50), set to trip, comprises part of the burden, the setting/pickup of the 50 relay can be used instead of the maximum short circuit current. We recommend against this approach because at 50 pickup (and up to at least 1.5 to twice pickup), the operating time of the 50 can be several cycles, which gives the CT time to saturate for currents higher than the 50 pickup. Thus we recommend calculating CT error for phase devices at the maximum short circuit current.

Current transformers are available in two broad grades; namely, Metering and Protection. Metering CTs are designed for accuracy which is typically 0.1% error at rated current, whereas protection CTs are typically designed for an accuracy where the error is no higher than 10% at 20 times rated CT secondary current flowing through a standard burden. Please note that the CT accuracy rating, discussed below, applies to the highest turns ratio of a multi-ratio CT, and for currents and burdens no higher than those upon which the accuracy rating is based. Separate accuracy ratings or other accuracy information for the other taps would have to be provided by the manufacturer. In the USA, a protective-relaying CT has no more than 10% ratio error when the voltage across its burden is equal to or less than the secondary terminal rated voltage specified in its accuracy rating. This rated voltage is applicable when it is developed across a standard burden at 20 times the CTs rated secondary current. The 10% error limit applies for all currents less than 20 times rated secondary current at the standard burden, or any lower standard burden used for CT accuracy rating. The voltage in the accuracy rating is normally very close to the CT knee voltage. The accuracy rating in the USA is comprised of a letter and the secondary terminal voltage rating discussed above; e.g., C200 or T200. The letters C or T associated with the rated voltage have the following meaning:

·

The C designation means that typical excitation curve data can be used in a simple calculation of the effective (corrected) CT ratio. The simple calculation of corrected CT ratio assumes that the effects of flux leakage are negligible. With this assumption, the voltage across the burden of a CT can be used directly to determine the CTs exciting current from typical excitation curves. The “C" designation cannot be used if the corrected CT ratio determined by this simplified calculation would not be within 1% of the CT ratio determined by test for the same conditions.

This information is considered CONFIDENTIAL and shall not be released to or discussed with any persons except (a) employees of ExxonMobil Affiliates who have an appropriate research agreement with ExxonMobil Research and Engineering Company (EMRE), and (b) consultants, contractors, or employees of third parties with whom proper secrecy agreements have been executed with EMRE or such ExxonMobil Affiliates. ExxonMobil Research and Engineering Company

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The T designation means that CT-ratio test data must be used to determine the effective CT ratio for various currents and burdens, because the simplified calculation method would not be accurate enough, as described above. The results of ratio tests for a given CT design are presented as a plot of secondary current versus primary current for various standard burdens, up to the highest standard burden which keeps the error below 50%. The currents are plotted in multiples of rated current up to 22 times the primary-side rated current.

Thus a C200 or T200 accuracy rating means the CT can develop 200 volts across the burden without exceeding 10% ratio error for all currents up to 20 times rated current and all standard relaying burdens up to the standard burden of 2 ohms (at 0.5 power factor). Twenty times current is 100 A (20 X 5 A), and the standard burden is 2 ohms in this case because 200V/100A = 2 ohms. The standard burden is the voltage rating divided by 100 for all CTs with a 5 ampere secondary. If it becomes necessary to determine the CT accuracy for a specific set of conditions, the accuracy can be calculated for the C-rated transformer using typical excitation data, or it can be determined from ratio test curves for T-rated transformers. As a first pass check of the accuracy of a CT for a specific application involving only phase devices, the CT is okay if the burden is equal to or less than the standard burden for its voltage rating, and if the available fault current is less than or equal to 20 times the primary winding rating. If these criteria are not met, either the accuracy has to be checked for the specific application or a higher-voltage-rating CT should be selected. ç

The accuracy rating of a CT is not meaningful in the determination of error for a residually connected ground relay, 51N. Determination of the ratio error for a 51N application is complicated by the fact that the CT in the faulted phase has to supply excitation current to itself and to the other CTs, which are excited by the voltage across the 51N. When high-burden electromagnetic ground-fault relays are involved, the total error approaches three times the excitation current of the “faulted" CT. With low-burden solid state ground-fault relays, the total error will be much less than with electromagnetic relays, and the excitation current added by the other CTs is likely to be considerably less than the excitation current of the “faulted" CT. For differential and N-type relays, another check must be made if the power system has a high X/R ratio. A momentary DC component in the power system current flow can easily saturate CT's (or any interposing ratio matching transformers) and cause false tripping of differential or residually connected relays. A high X/R ratio will occur where current limiting reactors are employed to reduce fault duty, for example, but can be found any place that a number of components are bussed together without significant cable lengths between them. To ensure no saturation takes place, the knee point voltage of the CT must satisfy:

ç

Vk > 2π TIRsec or Vk > (Xpri/Rpri)IRsec

ç

Where: I-

symmetrical secondary current in amperes (usually fault current)

Rsec -

total secondary resistance

T-

primary circuit time constant in cycles

(Xpri/Rpri) -

X/R ratio of the primary circuit involved in the fault calculation

It is not necessary to know the actual values of X and R just the ratio. This ratio can be found in handbooks and is usually only a function of the size of the transformer, generator, etc. Under some circumstances, the current with the longest time constant may not be short circuit current. The highest product of time constant and current magnitude determines the required Vk. Additional information is contained in ANSI C37.110. ç

In Europe, a protection CT may be designated “100 VA 5 P 20" where the 100 VA is the burden, and accuracy is 5% or less error at a primary current of 20 times the CT's rated primary current. The “P" stands for protection; i.e., a CT used for protective relaying. The IEC Standard 185 covering CT's does not indicate how to deal with currents or burdens higher than those in the rating designation. "Overdimensioning" of CT's for transient performance is discussed in IEC 60044-6. This information is considered CONFIDENTIAL and shall not be released to or discussed with any persons except (a) employees of ExxonMobil Affiliates who have an appropriate research agreement with ExxonMobil Research and Engineering Company (EMRE), and (b) consultants, contractors, or employees of third parties with whom proper secrecy agreements have been executed with EMRE or such ExxonMobil Affiliates. ExxonMobil Research and Engineering Company

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Whenever a CT circuit is required at some remote location, such as in a control room for an ammeter, and the remote circuit does not form an essential part of the protection circuit, an interposing CT located in the substation should be connected in the protection circuit to isolate the remote circuit from the protection circuit. An isolating CT with a ratio of say 5/1 or 5/0.5 will have the added advantage of providing a higher driving voltage to the remote circuit and permit the use of a smaller cross-section cable. 6.1

CORE BALANCED (ZERO SEQUENCE) CURRENT TRANSFORMERS

See DP XXX-D. A core balanced current transformer consists of an iron toroid with a winding around the iron core. When cable is passed through the toroid without a ground return path, and the sum of the currents in the cable is ZERO, there will be no flux in the iron core (core balanced), whatever the magnitude of the three primary currents. However, any zero sequence (ground fault current) in the three-phased primary cable currents will create a flux in the iron core and a current in the secondary winding on the iron core proportional to the ground fault current in the primary circuit. ç

Note that the conductors must be properly centered in the core "window", otherwise local saturation of a portion of the core may occur, causing an unwanted output from the transformer during high phase current flows. Presence of other magnetic materials in the immediate vicinity of the core window may have a similar effect. We use core balanced current transformers extensively on feeders and motor protection circuits to supply ground relays. Where possible, the zero sequence CT and the ground fault relay should be purchased as a unit. The ground fault relay is normally instantaneous and set to be very sensitive since it is not subject to the transient-offset CT imbalances of residually connected relays. 7

POTENTIAL TRANSFORMERS

These are generally two-winding transformers that are used to reduce system voltages to 110 V or 100 V for relays and metering. Due to the high cost of potential transformers above 15 kV, it is common to use capacitive coupling circuits, where the accuracy need not be as high as for metering. ç

Failure of unfused potential transformers has resulted in several plant upsets over the years. GP 16-12-01 & 02 show primary and secondary fuses on medium and low voltage PT's. 8 8.1

BASIC DESIGN CONSIDERATIONS

PROTECTION PHILOSOPHY

A good protective relaying system should have the following attributes:

·

It should operate in the shortest time possible consistent with reliable and selective operation, and with the economics of design. Economics often dictate that it is not justified to use the fastest and most sensitive protection in the form of high-speed differential relaying.

·

It should shut down/isolate the minimum amount of the electrical system necessary to remove the faulty part of the network; i.e., it should be selective. Every level or zone of the electrical system should have fast first-line, or primary relaying. In addition, backup relaying should be provided where practical. Backup relays for one part of a system are often the first-line protection for another part of the system. For example (assuming no bus-differential relaying), a fault on an outgoing feeder should be cleared by the feeder protection, and not by the main-bus's primary protection. However, if the feeder protection fails to clear the fault, the main bus's primary protection should operate as the backup to the feeder protection. Backup protection for part of a system is not always the primary protection for another part; e.g., stuck-breaker protection; and 51 or 51V backup of a differentially protected bus or generator.

·

It should be highly reliable in terms of repetitively operating per the setting, and in terms of operating when it is supposed to and not operating when it shouldn't. This not only encompasses the selectivity discussed above, but includes, for example: motor locked-rotor protection operating for a locked rotor condition, but not for reacceleration current; transformer primary-feeder 50-relaying tripping for a primary-feeder fault, but not for transformer inrush current, and not for a transformer secondary fault; a differential relay tripping for faults in its zone, but not for faults outside its zone.

This information is considered CONFIDENTIAL and shall not be released to or discussed with any persons except (a) employees of ExxonMobil Affiliates who have an appropriate research agreement with ExxonMobil Research and Engineering Company (EMRE), and (b) consultants, contractors, or employees of third parties with whom proper secrecy agreements have been executed with EMRE or such ExxonMobil Affiliates. ExxonMobil Research and Engineering Company

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It should be well documented. One-lines, three-line diagrams, settings sheets and the actual field settings should all be consistent. Logic diagrams should be provided for microprocessor or "numerical" relays. Relay application brochures for all relays used should be available for maintenance personnel.

With the above attributes, a well-designed protection system minimizes damage and downtime of faulty parts of the system, and minimizes the impact of electrical faults on the healthy part of the system, thereby enabling plant operations to progress with minimum interruption. 8.2

OVERCURRENT DEVICE COORDINATION (SELECTIVITY / DISCRIMINATION)

To ensure that all of the protection-system attributes discussed above are met, a protective device coordination study is required. The most common form of study covers the selection, setting and coordination of overcurrent devices; although voltage, power, and impedance relays may sometimes be involved. For overcurrent devices in series with a fault, coordination requires that the overcurrent protection closer to the fault (the downstream devices) interrupt the fault before backup protection (the upstream devices) can operate. Overall, the objective is to provide the fastest practical protection while ensuring that no healthy equipment is taken out of service unnecessarily. For the hypothetical system shown in Figure 20, Breakers 2 and 3 do not have to coordinate with each other, nor do Breakers 4 and 5, since no healthy part of the system would be affected unnecessarily by this lack of coordination. However, Breakers 1 must coordinate with Breakers 2 and 3, and Breakers 2 and 3 must coordinate with Breakers 4 and 5. If there were a transformer between Breakers 2 and 3 in Figure 20, there could be reasons to coordinate Breakers 2 and 3; e.g., if Breaker 2 is the incomer of a secondary selective substation. Overcurrent-device coordination analysis is performed on log-log paper (or computer screen equivalent), with the current on the X-axis and time on the Y-axis. See Figure 32. Where there is a transformer between overcurrent devices, the time-current curves of both devices are referred to the same voltage level. To achieve coordination, a minimum amount of time is required between the upstream and downstream overcurrent-device curves at the maximum current that will exist simultaneously in both devices. The minimum amount of time required to achieve coordination is called the coordination interval or coordination margin. This form of coordination is sometimes referred to as time grading. Another form of coordination is current grading, where an upstream device is set above the fault level at a downstream relay's location. This is illustrated in Figure 21, where an instantaneous relay (A) on the primary of a transformer is set above the secondary-side fault level (at location B) times any overreach factor applicable to the instantaneous relay at A. Coordination Factors - Various coordination factors that must be accounted for in the determination of the minimum required coordination interval are as follows:

·

Accuracy of the time-current curves relative to error / tolerance associated with both the upstream and downstream curves; overtravel of upstream relays; and the effect of pre-loading on minimum-melt curves of upstream fuses. Relay error is typically a percent of the setting time, with a fixed minimum error time.

·

“Downstream" current-transformer error. CT error typically contributes to the coordination margin by reducing the current seen by the relay, thus making the downstream relay slower than the curve indicates. The upstream relay would not have a compensating delay if the upstream CT is more accurate, which can happen when the upstream CT has a higher turns ratio. Unless a determination is made of the actual effect of CT error, a value of 10% of the downstream-relay time (at maximum current) is typically used to account for CT error.

·

“Downstream" circuit breaker operating time, which does not have to be added if the operating time is already built into the device curve as is the case for direct-acting-trip devices.

·

The relevant factors from above are summed and a safety factor is usually added to determine the coordination margin. The amount of safety factor is a matter of judgement. Assuming all of the other factors covered above are separately accounted for, the safety factor may be taken as 0.05 second for static relays and up to 0.1 second for electromechanical relays. Where coordination is to be achieved across a delta-wye transformer, a current-shift is required for (wye) secondary-side phaseto-phase faults. For any given time, draw a dashed curve by shifting the transformer-secondary-51-relay curve right by multiplying the currents by 1.16. This accounts for the 1.0 per unit current in one primary phase when there is a 0.866 per unit phase-to-phase fault current in two secondary phases. Coordinate the primary-side relay with the shifted dashed curve.

This information is considered CONFIDENTIAL and shall not be released to or discussed with any persons except (a) employees of ExxonMobil Affiliates who have an appropriate research agreement with ExxonMobil Research and Engineering Company (EMRE), and (b) consultants, contractors, or employees of third parties with whom proper secrecy agreements have been executed with EMRE or such ExxonMobil Affiliates. ExxonMobil Research and Engineering Company

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Known or assumed values can be used for any or all of the above factors to determine the coordination margin. Coordination Margins - Margins for various coordination situations are discussed in the following:

ç

8.3

·

For relay to relay coordination, the coordination margin is the sum of upstream relay error and overtravel, downstream relay error and CT error, downstream breaker operating time, and a safety factor. The coordination margin is typically 0.3 to 0.35 for static relays, and 0.4 second for electromechanical relays. Static relays have very low overtravel. They are often more accurate than electromechanical relays, and tend to cause less CT error due to their lower burden.

·

A low-voltage switchgear breaker with time-delayed direct-acting trip (and no instantaneous unit) can coordinate with downstream direct-acting trips and fuses if the upstream breaker's direct-acting-trip curve is above the maximumclearing curve of the downstream device. Do not try to make molded case circuit breakers (MCCBs) coordinate with each other by disabling the upstream instantaneous unit, because the instantaneous unit is necessary to the safe operation of the MCCB.

·

Some contactors exhibit an intentional (or unintentional) time delay on drop out. As a result, the upstream relaying must be set no faster than the motor protection plus drop out time of the contactor. Another way this can happen is if "flyback" diodes are fitted to a vendor's standard (d-c) contactor coil.

·

For an upstream time-delayed relay to coordinate with a downstream fuse or direct-acting trip, the coordination interval is equal to the relay error plus relay overtravel plus a safety factor. This interval is typically 0.15 to 0.25 second, and is added above the maximum clearing characteristic of the fuse or direct-acting trip.

·

Fuse to fuse coordination is discussed in detail earlier in this Design Practice, under the side heading “FUSES". In summary, fuse to fuse coordination is most easily achieved using the manufacturer's selectivity ratio guides. Otherwise, use the maximum-clearing and minimum-melting I2t data for current-limiting operation. For non-currentlimiting operation, use the maximum clearing curve of the downstream fuse, and the minimum melting curve of the upstream fuse. The minimum-melting curves have to be adjusted for fuse pre-loading per the manufacturer's instructions. Coordination is achieved when the maximum clearing characteristic of the downstream fuse is below (or lower than) the minimum melting characteristic of the upstream fuse (adjusted as required).

·

For an upstream instantaneous relay to coordinate with a downstream current-limiting fuse, the fuse's peak let-through current times 0.7 must be less than the rms pickup of the instantaneous relay. This is discussed in more detail in the earlier section entitled PROTECTIVE DEVICE TYPES AND APPLICATION, under the side-heading FUSES, where peak let-through fuse data is discussed.

·

Upstream fuses on the primary of a transformer must not be in their current limiting range for fully offset secondary faults. For coordination purposes, the upstream fuse minimum-melt characteristic must be shifted left for the preloading effect per manufacturers guidelines, and the downstream device curve must be shifted right by a factor of 1.16 times current values for phase-to-phase faults when the transformer is delta-wye, as discussed earlier in this section under the paragraph that begins with Coordination Factors. BACK-UP PROTECTION

Whenever possible, we try to provide back-up protection. This is often inherent in our time and current graded protective schemes. For example, in Figure 27, for a fault downstream of Relay 1, Relay 2 will “see" the same current as Relay 1 and operate a short time after Relay 1 if Relay 1 fails to open its associated circuit breaker. Thus, Relay 2 is providing back-up protection for Relay 1. Likewise, Relay 3 will provide back-up for Relay 2. It may also provide a second stage of back-up for Relay 1 if its current setting is low enough to “see" faults downstream of Relay 1. Relay 3 will also provide back-up for Relay 4, the generator differential protection. Per the configuration in Figure 27, Relay 3 is the primary protection for the generator bus. We do not require back-up protection for ground faults in transformer main secondary connections with impedance grounding (see GP 16-02-01), as this condition cannot be easily detected on the primary of a delta/star transformer. To provide back-up protection would require duplicating the relays on the transformer secondary, or restricted earth fault relaying. 8.4

GROUND (EARTH) FAULT RELAYING

See DP XXX-D. Ground relaying follows the same general rules as phase fault relaying but has the following additional points to consider:

This information is considered CONFIDENTIAL and shall not be released to or discussed with any persons except (a) employees of ExxonMobil Affiliates who have an appropriate research agreement with ExxonMobil Research and Engineering Company (EMRE), and (b) consultants, contractors, or employees of third parties with whom proper secrecy agreements have been executed with EMRE or such ExxonMobil Affiliates. ExxonMobil Research and Engineering Company

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·

System neutral grounding method affects how much ground fault current is available, with low resistance grounding resulting in the ground fault current being much lower than the phase-fault current.

·

Transformers with certain winding and/or grounding configurations do not pass zero-sequence current from the secondary side to the primary side.

· ·

Capacitive currents. High burden of some ground fault relays can affect current-transformation accuracy.

When sizing neutral resistors, GP 16-02-01 requires that the ground current be not less that 15 times the lowest reliable operating current of the least sensitive outgoing feeder ground relaying, and not less than five times the lowest reliable operating current of bus ground relaying. It should be noted that for most induction disc type relays, the lowest reliable operating current may be as high as 1.5 times setting (pickup). On solidly grounded low-voltage systems, where local codes permit, we do not provide ground-fault relays on feeder circuits when there is sufficient ground fault current to operate phase-fault devices. “Sufficient" current, per GP 16-04-01, means the phase protection of a given feeder must operate in less than two seconds for a phase to ground fault at the load end of the circuit with an arc voltage of 40 volts; otherwise a ground-fault relay must be added to the circuit. A delta / wye transformer, for all practical purposes, offers an infinite impedance to zero sequence currents, therefore, the primary ground relaying of a delta/wye transformer is instantaneous since there is no coordination problem with secondary-side relaying. For other transformer winding and grounding configurations, the zero sequence impedance of the transformer should be ascertained. When there is a solid phase to ground fault, the faulted phase potential falls to zero, and the capacitive (charging) current in that phase to ground will be zero. In a resistance grounded medium voltage system the two healthy phases will have capacitive (charging) current of 1.73 times normal; therefore every ground fault relay at that voltage level that is part of the same neutral grounding system will see a capacitive current equal to 3 times the capacitive (charging) current of one phase to ground of the cables downstream of the relay. (For a solidly grounded system, the relays would see 1 times the charging current of one phase.) The relays must be set above this capacitive charging current. The output from core balanced (zero sequence) current transformers is low because:

· ·

Often there is only half a turn on the primary.

·

The physical separation between the primary and the core is greater both because there are three conductors on the primary and because the CT is generally slipped over the main power cable with space between the cable and the CT.

The fault current being measured is generally much less than phase fault current.

For the above reasons, it is possible that the actual primary current required to cause pickup of a relay connected to a core balanced current transformer is two to ten times the relay setting. Therefore it is recommended that core balanced CTs and their associated relays be purchased as a unit. Where ground relaying is employed, it should wherever possible be of the core balanced type CT in preference to residually connected phase CTs. 8.5

MOTOR PROTECTION

Typical motor protection arrangements that comply with the Global Practices are shown in Figure 28. It should be noted that one-line diagrams do not include the following which have been shown in Figure 28 to give the complete protection details:

· ·

Direct acting trip device numbers, number of elements, trip signals. Trip signal from fuse striker pins.

Motor overload and locked-rotor protection are covered in detail earlier in this practice under PROTECTIVE DEVICE TYPES AND APPLICATION, side heading THERMAL OVERLOAD RELAYS (49) AND LOCKED ROTOR PROTECTION. Motor circuit ground fault relaying is covered earlier under the side heading GROUND (EARTH) FAULT RELAYING. LV motors controlled by contactors are protected by three-element thermal relays for overloads, and by fuses or molded case circuit breakers for short circuits. Molded case circuit breakers have an instantaneous trip, and in some cases, have a thermal or solid state time-delayed trip intended for motor thermal protection. In these cases, we still use separate thermal overload relays to trip the contactor as they follow the motor thermal capability more closely. The molded case circuit breaker thermal elements are set above the contactor's thermal overload relays.

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Whenever a relay trips a contactor, the capability of the contactor should be checked to ensure that the relay does not require it to open for a current in excess of its rating. The fuse or circuit breaker should take over above the contactor capability limit. Basically, we apply the same protection to LV motors controlled by switchgear circuit breakers as we do for contactors. The differences being that:

·

We accept the breaker direct acting trips for overload protection, but back them up with a secondary thermal element in one phase.

· ·

We add an undervoltage relay if undervoltage protection is not otherwise provided.

2. ç

We require a ground fault relay, for solid or low-resistance grounded systems, with the relay supplied from a corebalanced current transformer. MV motor protection incorporates the following:

·

Undervoltage protection if not otherwise provided. Critical motors should use two-out-of-three tripping for undervoltage, with appropriate PT fusing (3 individually-fused PT's, or two PT's with 4 fuses).

·

Hand-reset lockout for all fault protection relays.

·

Overload protection in three phases.

· ·

Locked rotor protection, in addition to overload relays, in at least one phase.

·

Differential protection on motors 2501 hp (1801 kW) and above, with a self-balancing scheme preferred per the lower sketch in Figure 15. Phase balance relays are not required by ExxonMobil Global Practices, however for large (>1MW) motors, they may be considered. Phase balance relays are available as phase-unbalance (simpler) and negative sequence (more sophisticated) types. The negative sequence type provides better protection with less false tripping than the unbalance type. With large motors, stator saturation during energization inrush can result in the relay seeing unbalanced current for up to a second. As a result, a time delay must be provided for these relays.

3.

8.6

Ground fault relay supplied from a core balanced current transformer.

GENERATOR PROTECTION

This is covered is DP XXX-B, but see also above Synchronizing Relays (25), Loss of Field Relays (40), Negative Sequence Relays (46), Voltage Restrained Relays (51V), Overvoltage Relays (59), Directional Relays (67 and 32), and Differential Relays (87). Points to consider when applying generator protection are: ç

8.7

·

Unless there is only one generator that always operates “in island", kW and kVAR can flow both to and from the generator.

·

The protective relays must protect the generator and the integrity of the electrical system, but they must not inhibit the generator from providing its full capability to the electrical system.

·

When operating in parallel with the power utility, detailed information will be required on the utility protective relaying in the area to determine the relay setting for separation from the utility.

·

If the generator is operating in parallel with other generators or the utility, fast fault clearance times will be required to maintain transient stability, i.e., generator differential and bus differential protection.

·

The Automatic Voltage Regulator (AVR) should be self-protecting, i.e., it should automatically change to manual, or a fixed setting, if faulty. It is not practical to protect for AVR faults with protective relaying. TRANSFORMER PROTECTION

As nearly all the power transformers we use are step-down with a delta primary winding and wye secondary winding, the following comments are based on such a transformer. However, many of the comments will apply whatever the transformer vector reference (see Figure 29):

This information is considered CONFIDENTIAL and shall not be released to or discussed with any persons except (a) employees of ExxonMobil Affiliates who have an appropriate research agreement with ExxonMobil Research and Engineering Company (EMRE), and (b) consultants, contractors, or employees of third parties with whom proper secrecy agreements have been executed with EMRE or such ExxonMobil Affiliates. ExxonMobil Research and Engineering Company

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·

Due to the relatively high impedance of the transformer, it is usually possible to apply primary-side instantaneous phase overcurrent protection set above the current in the primary that would flow for a short circuit on the secondary terminals, i.e., the relay will not “see through" the transformer.

·

Instantaneous ground relaying is applied to the primary, preferably with a core balanced current transformer, but three current transformers residually connected are acceptable.

·

Three overcurrent elements are used in the supply to the primary which are set to coordinate with relaying downstream of the transformer.

·

Intertripping of the secondary breaker when the primary feeder breaker opens should be implemented in the case of a spot network substation.

·

Tripping of transformer primary and secondary breakers is required for operation of the transformer fault pressure and 51G relays; for operation of restricted-earth-fault relaying (if provided); and, in spot networks, for operation of the 67 relay, and the 67N relay (if provided). For secondary-selective substations, the secondary breaker opens via the transfer logic for faults upstream of the incoming breaker.

·

A Buchholz or Fault Pressure relay is required on all transformers 500 kVA and above.

·

A ground overcurrent relay is required in the secondary neutral of all transformers 500 kVA and above where the neutral is low resistance or solidly grounded. For high-resistance grounding of a transformer neutral, a ground overvoltage relay is provided across the neutral resistor, and is set to alarm. For transformers below 500 kVA, we accept that the connection from the transformer secondary to the secondary circuit breaker is only protected by the phase overcurrent (51) relays on the transformer primary and that they may not be set low enough to protect for arcing faults on the secondary connections.

·

For relaying of transformers supplied from tapped feeders, and those with fuses on the primary, see GP 16-02-01.

·

For transformers 10 MVA and larger, differential protection is provided, as discussed under PROTECTIVE DEVICE TYPES AND APPLICATION, DIFFERENTIAL RELAYS earlier in this Design Practice. TRANSFORMER SECONDARY PROTECTION

Protective relaying on transformer secondary breakers is required to coordinate with downstream relaying and is selected accordingly. ç

8.9

POTENTIAL TRANSFORMER PROTECTION

Below 36 kV, usual practice is to provide primary fusing for bus, generator and motor PT's. PT fuses are available for voltages as high as 138 kV but may not be able to handle fault currents associated with these higher voltages. Design of the relaying downstream of the PT's may need to take into account a blown-fuse condition, to avoid unwanted tripping. Sometimes this requires a separate voltage transformer fuse failure (VTFF) relay, or relay software function. If PT's are connected phase-tophase, both leads of each PT will need to be fused in order to detect a blown PT fuse. The same is true for 27 relays where twoout-of-three tripping is employed. 8.10

BUSBAR PROTECTION

All busbars are included in time graded protection zones. In addition, main incoming substation busbars and generator busbars are generally fitted with differential protection. Where there are more than two power sources, we normally provide stuckbreaker protection. 8.11

CABLE (FEEDER) PROTECTION

Protective relaying for feeders will vary depending on the load and protective relaying downstream. Transformer and motor feeders are covered in this Design Practice, and tapped feeders are dealt with in GP 16-02-01. Distribution feeders to a bus require overcurrent protection in three phases, and an overcurrent ground relay, preferably supplied from a core balanced current transformer, for low resistance or solidly grounded systems. Important feeders between buses at the same voltage level can be fitted with differential (87) or pilot wire differential (87P) protection to eliminate one selectivity time step. This information is considered CONFIDENTIAL and shall not be released to or discussed with any persons except (a) employees of ExxonMobil Affiliates who have an appropriate research agreement with ExxonMobil Research and Engineering Company (EMRE), and (b) consultants, contractors, or employees of third parties with whom proper secrecy agreements have been executed with EMRE or such ExxonMobil Affiliates. ExxonMobil Research and Engineering Company

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SECONDARY SELECTIVE SUBSTATION PROTECTION

This is fully covered in GP 16-12-02. Two points to watch out for:

·

"83" relays that have too low pick up voltage combined with LED-type transfer-ready indicating lights - can result in the relay picking up on DC voltage excursions. Such an arrangement will also not pass the "...series resistor shall be sized to prevent activating associated 83 relay due to lamp short circuit..." requirement.

·

Switchgear-quality auxiliary relays should be used. Less-robust control relays have suffered from coil and contact failure. These are not suitable for switchgear service.

8.13

SPOT NETWORK SUBSTATION PROTECTION

Incoming circuit breakers to a spot network substation require directional phase overcurrent (67) and directional ground (67N) relays which look back towards the source. These must operate ahead of the incoming and bus-tie phase and ground overcurrent relaying to ensure that a fault on an incoming feeder does not trip both incomers. For a spot network with incoming transformers, restricted earth fault relaying may be substituted for the 67N. For a spot network without incoming transformers, differential or pilot-wire relaying around the source feeder is required if the source bus-tie breaker is normally closed, and is preferred if the source bus-tie is always open. A relayed tie breaker is provided when it is important to maintain supply to the loads on one of the busses for a bus fault or for an uncleared feeder fault on the other bus. When a relayed bus-tie breaker is provided, partial differential zones on each bus (encompassing the incomer and tie-breaker) should be seriously considered to save a time step in the incomer (and possibly in the source) relaying. When partial differential protection is not provided for a spot network with incoming transformers, the incoming 51N is not needed because the 51G in the transformer neutral covers all the functionality of the 51N. The following guidelines apply to relaying for a spot network substation (Refer to Figure 47):

· ·

The spot-network incoming breakers should be transfer tripped by the opening of their respective source breakers.

·

If the source bus to the spot network is always effectively a single bus, the 67 relays can be set to be fast and sensitive, but the 67 relays must not operate for motor backfeed to a fault on the source bus or one of its feeders.

·

If the source buses to the spot network are or can be electrically separated from each other while the spot network has both incomers in operation, the 67 must coordinate with outgoing feeders from the source bus at the level of fault current that could pass through the spot network. If the spot network does not have transformers which block the flow of zero-sequence current, the 67N must likewise coordinate with the source-bus feeders.

·

In the absence of partial-differential relaying, the bus-tie 51/51N relays, if provided, must coordinate with the outgoing feeders and the incomer 67 and 67N or restricted-earth-fault relays. This coordination applies up to the current from one transformer, since that is the most current the tie will see.

·

In the absence of partial-differential relaying (discussed below), the incoming-line 51 phase and ground relays protecting the spot-network bus must be selective with the bus-tie relays (if provided) and with the outgoing feeders and the 67/67N relays.

The spot-network source breakers should be tripped by the respective 67 and 67N or Restricted Earth Fault relays in the spot network, in addition to being tripped as usual by the transformer fault-pressure and 51G relays.

With a relayed bus-tie breaker in a spot network substation, a step of coordination can be saved by using partial differential phase and ground relays which operate on the sum the phase-fault or ground-fault current into a bus from its incomer and the tie breaker. See Figure 30. The partial-differential relays must coordinate with the outgoing feeders on the bus because the outgoing feeders are not in the differential relay circuit. This coordination must occur at twice the fault current from one incomer. When the spot network has incoming transformers, the 51G in the transformer neutral must coordinate with the partial differential ground relay at the ground-fault current from one source. Likewise, the primary side 51 relays must coordinate with the partial differential 51 relays at the maximum phase-fault current from one source. With a partial differential setup, if the bus-tie breaker fails to operate for a phase fault on one bus, the other bus's partialdifferential relaying will not operate. Therefore, the backup will be the feeder relaying at the source bus - unless breaker-failure relaying is added to the tie breaker as backup to trip the incomers. If an incoming breaker fails to operate for a primary side phase fault (transfer trip or 67 trip signal), the only backup is the primary 51 relay looking through two transformers. If this This information is considered CONFIDENTIAL and shall not be released to or discussed with any persons except (a) employees of ExxonMobil Affiliates who have an appropriate research agreement with ExxonMobil Research and Engineering Company (EMRE), and (b) consultants, contractors, or employees of third parties with whom proper secrecy agreements have been executed with EMRE or such ExxonMobil Affiliates. ExxonMobil Research and Engineering Company

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backup is not considered adequate or desirable, incomer breaker failure relaying should be provided to trip the spot-network bus tie, thereby saving the supply to one bus. 8.14

RESTRICTED EARTH FAULT PROTECTION

Restricted earth fault protection is a ground-fault differential zone covering the grounded wye winding of a transformer, and its incoming bus duct or cable. Various relay types can be used for this application, including overcurrent, overvoltage, and differential. This protection can be used in spot-network relaying in place of the 67N. The differential protection (87T) on large transformers (with an appropriately sized neutral grounding resistor) should be sensitive enough to protect more than half the winding from a ground fault, without the need for restricted-earth fault protection. In any case, the transformer fault-pressure relaying provides fast and relatively sensitive protection. 8.15

CAPTIVE TRANSFORMER PROTECTION

The protection of captive (or unit) transformers for generators and motors is the same as for other transformers, except for the following:

·

On the motor side of a step-down transformer, the wye winding may be high-resistance-grounded, with an overvoltage relay (59) sensing zero-sequence voltage across the resistor. The overvoltage relay is used to trip and/or alarm.

·

On a generator step-up transformer, the generator-side winding is often wound in delta, and the generator neutral is high-resistance grounded, with an overvoltage relay (59) sensing zero-sequence voltage across the resistor. The overvoltage relay is normally used to trip the generator.

The nature and protection of transformers associated with variable speed drives is beyond the scope of this Design Practice. 8.16

CALCULATION PROCEDURE

Design specifications should include transformer sizes, number of current transformers and their ratio, relays types (at this stage, the full details of how inverse a relay is or its range of settings are not normally included), and number of elements, potential transformers with their ratio, and sizes of large motors. The contractor takes over from this point. The contractor is responsible for final sizing of all electrical components and selecting CT ratios. GP 16-02-01, Power System Design, specifies that contractors shall furnish relay data and relay coordination, and presents general requirements for the documentation of relay data and coordination. This design practice gives the requirements in greater detail and should be used as a guide for documentation of relay data and coordination. 8.17

DOCUMENTATION REQUIRED FROM CONTRACTOR

Two types of relay documentation are required as specified in GP 16-02-01. These two types are: 1.

2.

8.18

Relay Data - A tabular presentation which identifies and shows the recommended settings for each adjustable relay and other protective device. The relay data shall also furnish calibration and check points for each device plus space to record the actual values for these points as measured in field tests. Relay Coordination - A set of time vs. current and time vs. voltage curves which show the characteristics of the relays and other protective devices at their recommended settings. The primary purpose of the coordination is to show graphical proof of the selectivity between devices. The coordination also shows the operating times of the protective devices at various values of fault currents. This permits checking that adequate protection has been provided for the electrical system components. WHEN CONTRACTOR SHOULD FURNISH RELAY DOCUMENTATION

GP 16-02-01 establishes when the contractor should furnish relay documentation to the Owner for approval. Relay coordination should be furnished on two occasions: 1. Before current transformer ratios and relay or other protective device ranges and characteristics are specified to the supplier. This preliminary issue of the coordination needs only to be complete and accurate enough to verify selection of the proper ratios, ranges, and characteristics. 2. When relay data is presented for final approval.

This information is considered CONFIDENTIAL and shall not be released to or discussed with any persons except (a) employees of ExxonMobil Affiliates who have an appropriate research agreement with ExxonMobil Research and Engineering Company (EMRE), and (b) consultants, contractors, or employees of third parties with whom proper secrecy agreements have been executed with EMRE or such ExxonMobil Affiliates. ExxonMobil Research and Engineering Company

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Relay data shall be presented to the Owner for approval when all characteristics of the electrical system and its loads are firmly established and when complete information has been received from vendors on the relays and other protective devices. The data should be presented early enough to permit the Owner to review it and to allow the contractor to complete the final copies before the data is needed in the field. A minimum time of two months should be allowed for review by the Owner and preparation of the final data by the contractor. A narrative should accompany the study, clearly stating the coordination philosophy (coordination intervals, backup relaying logic, breaker failure schemes - if any, and autotransfer operation). The preparation of the preliminary relay coordination is important. This coordination minimizes the need for changes in relays and current transformers after approval of manufacturer's drawings or delivery of equipment. Such changes can delay delivery of the equipment and, thereby, lead to delay in project completion. 8.19

SAMPLE RELAY DATA AND COORDINATION

A set of sample relay data and coordination for two substations of a typical refinery process unit is included herein. One-line diagram, Figure 33, covers the power circuits and protective relaying of the substations. The contractor may be given this sample (i.e., Figures 31 through 41 and text from CALCULATION PROCEDURES through RELAY COORDINATION REQUIREMENTS) to use as a guide when preparing his data and coordination. 8.20

RELAY DATA REQUIREMENTS

Contractor should furnish relay data on a tabular form similar to the “Relay Settings Record" shown in Figure 31 unless otherwise advised by the Owner. On some projects, the Owner may request that the relay data be prepared on his standard Form. For such cases, Project Management will advise the contractor and will furnish copies of the Owner's Form to the contractor. Sample relay data is shown in Figures 34 and 35. The following features should be noted:

· ·

Data should be provided for each relay even when there are multiple relays per circuit, each having the same setting.

·

For overcurrent relays, the calibration point should be specified at five times pickup current and the test point at two times pickup current. Different values may be used for situations where it is desirable to check a relay's performance at a specific point on its curve.

·

Relay operation times at the calibrate and test points should be given in seconds and cycles. This aids the test engineer who often measures operating timers with a cycle counter.

·

The data shall include symbols for identifying each relay with its characteristic curve shown in the coordination.

·

Calibrate and test points are not required for circuit breakers having direct acting trip elements unless requested by the Owner.

·

Fractional time dial settings may be used. Such settings should be limited to quarters, such as 1.25, 2.5, 3.75, unless the relay time dial is calibrated in other fractional values.

8.21

Blank columns should be provided to record the actual values of current (or volts) and times used in the field to calibrate and check each relay.

RELAY COORDINATION REQUIREMENTS

Contractor should furnish relay coordination curves on logarithmic time-current characteristic paper similar to that shown in Figure 32. One set of curves shall be furnished for each substation. Curve sheets shall be provided for phase relays and other phase protective devices at each voltage level. Separate curve sheets shall be provided for ground relays and other ground protective devices. Values of symmetrical maximum and minimum short circuit currents shall be shown on each curve sheet. Sample coordination curves are shown in Figures 36 through 41. The following features should be noted:

·

A time vs. voltage curve for undervoltage relay 27 used to initiate automatic transfer should be shown for each secondary selective substation. A percent voltage scale corresponding to fault current values should be plotted in accordance with the IEEE reference listed in GP 16-02-01.

This information is considered CONFIDENTIAL and shall not be released to or discussed with any persons except (a) employees of ExxonMobil Affiliates who have an appropriate research agreement with ExxonMobil Research and Engineering Company (EMRE), and (b) consultants, contractors, or employees of third parties with whom proper secrecy agreements have been executed with EMRE or such ExxonMobil Affiliates. ExxonMobil Research and Engineering Company

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·

For phase relaying, the effect of the higher current seen in one primary phase during phase-to-phase faults on the secondary of delta-wye transformers should be shown by moving the time vs. current curve of the secondary phase overcurrent relay 16% to the right (see Figure 44).

·

For ground relaying, check the effectiveness of primary-side phase relaying to act as backup for a ground fault on the secondary of a solidly-grounded delta-wye transformer, by shifting the primary 51 curve to the right by a factor of 1/0.58 applied to the current values. Protection of the transformer is effective if the shifted primary 51 curve is below the transformer through-fault protection curve for a reasonable range of fault currents.

·

The appropriate “through-fault protection curve" for power transformers should be shown. The appropriate curve for almost all applications is the one for infrequent fault incidence. The only situation for which the frequent-fault-incidence curve should be used is to check that an outgoing feeder subject to frequent-faults (normally an overhead line) has an overcurrent device which provides through-fault protection for its supply transformer. (Note: Figures 36 and 39 show a “transformer damage point" because they have not been updated to show the “through-fault protection curve".)

·

Relay curves for all feeders need not be shown on the coordination diagram. Generally, it is only necessary to show the curves for the highest set feeder relays to prove feeder selectivity with the upstream relays.

·

The sample only shows the coordination curves for one 2300 volt motor (Figure 38). Contractor should furnish similar curves on separate sheets for each motor rated above 600 volts. The motor withstand point at operating temperature for locked rotor current should be shown. Also, a plot of motor current from locked rotor to full load should be shown. In order to show this plot, motor starting time must be determined.

·

Each curve should be identified with a symbol listed in the relay data.

·

Although not shown in the sample, contractor shall show, where applicable, the safe insulation heating limit (short circuit withstand) for feeder cables supplying buses and power transformers rated above 600 volts per GP 16-02-01. The heating limit curve should be on the same curve sheet with the feeder protective device. The device setting should protect the cable for currents up to the maximum available short circuit current. SQUIRREL CAGE INDUCTION MOTOR RELAY SETTINGS

27M - Undervoltage relay used to open motor control devices which do not automatically drop out when voltage drops below about 60 to 70%. Such devices include circuit breakers, mechanically latched contactors, and dc-controlled contactors with low drop-out voltage. The 27M function is incorporated in automatic reacceleration control schemes to trip all nonreaccelerating motors, and all reaccelerating motors that are tripped before they are reconnected for reacceleration. This reacceleration-control 27-relay usually operates with a definite time characteristic set to trip motors in about 0.35 to 0.5 seconds for voltages below about 65%. Some motors are not tripped at the outset of an undervoltage so they can reaccelerate immediately upon the return of voltage. Such motors, and reacceleration control schemes in general, require a 27M to abort reacceleration if the undervoltage persists so long that reacceleration is no longer feasible or safe. The 27M used to abort reacceleration is normally set to operate after about 5 to 10 seconds of voltage below about 65% volts. 49A - Thermal alarm relay can be set anywhere from 100% to 110% motor full load. 49 - Thermal overload relays are normally set to pick up at 110 to 115% of motor full load amperes (FLA) for 1.0 service factor motors, and at 125% of FLA for 1.15 service factor motors. See THERMAL OVERLOAD RELAYS AND LOCKED ROTOR PROTECTION earlier in this practice for discussion of using 49 relays for locked rotor protection. 50 - Must be set about 10% to 20% above locked rotor current, including any asymmetry to which it is sensitive. With a relay that is fully sensitive to d-c offset, settings are generally about 200% locked rotor current. 50GS - Supplied from a core balanced CT. Setting should be as low as practical, but above 3 times the charging current of one phase on low-resistance-grounded systems, or above the charging current of one phase on solidly-grounded systems. In any case, it is recommended that the ground fault relay not be set to less than 10% of the CT rating or 1% of the motor locked rotor current, whichever is greater. Based on the CT turns ratio, pickup settings equivalent to primary currents of 5 amperes and 10 amperes are common, which may result in actual relay pick-up in the range of 10 amperes to 30 amperes due to the low output of core balanced CTs. Electromagnetic-type relays are set for "instantaneous" tripping. Electronic relays should be set for 50-100 ms definite time delay, to avoid false tripping. See also DP XXX-D. 50N - Not used unless a core-balance CT cannot be fitted. Residually connected instantaneous relays must either have a small time relay added, or a stabilizing resistor fitted (see Figure 42) to prevent tripping during motor starting. For medium-voltage motors, setting should be such that the Lowest Reliable Operating Current is not more than 6.7% (one fifteenth) of the current passed by the neutral resistor (see GP 16-02-01 on sizing neutral grounding resistors). This information is considered CONFIDENTIAL and shall not be released to or discussed with any persons except (a) employees of ExxonMobil Affiliates who have an appropriate research agreement with ExxonMobil Research and Engineering Company (EMRE), and (b) consultants, contractors, or employees of third parties with whom proper secrecy agreements have been executed with EMRE or such ExxonMobil Affiliates. ExxonMobil Research and Engineering Company

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For low-voltage motors, setting should not be more than 40% of maximum three-phase fault level. Setting must not be too sensitive, as the performance of each of the three CTs will not be identical. Usual setting is in the region of 20 amps for medium-voltage motors. Unless special CT's are fitted, the setting should not be less than 10% of the phase CT ratings. This is a locked rotor protection relay, which is discussed in detail above under THERMAL OVERLOAD RELAYS AND LOCKED ROTOR PROTECTION. MCC FEEDER RELAY SETTINGS

The supply circuit to an MCC usually does not have an automatic-tripping circuit breaker when the MCC is in the same building as the supply switchgear. Supply to a TAPC has a tripping breaker. When there is a tripping circuit breaker, the overcurrent devices should be selective with the following:

·

Largest motor relaying.

·

Largest reacceleration current, with care that multiple steps in rapid succession do not cause the relay to operate.

Note that GP 16-02-01 permits non-selectivity with a large single load on the basis that the loss of the large single load would result in a plant shutdown. See GP 16-02-01 for permissible exceptions. 8.24

TRANSFORMER-SECONDARY RELAY SETTINGS 51 - Phase relaying protects the main bus, protects the transformer against through faults, acts as backup for the outgoing feeders, and should be set as follows:

·

Coordinate with the highest set downstream relaying. The 51 relay time-current characteristic should be enough below the transformer through-fault protection curve (for infrequent-faults) such that the transformer primary 51 relay curve can fit selectively above the incomer 51 relay curve and sufficiently below the transformer damage curve. See TRANSFORMER PRIMARY RELAY SETTINGS below.

·

Set not to operate for the largest reacceleration current (including already running motors), with care that multiple steps in rapid succession do not cause the relay to operate.

·

Set not to operate for starting of largest motor with all others already running.

·

Set pickup no lower than 125% of transformer forced cooled rating.

·

Set pickup no higher than 250% of transformer forced cooled rating, if possible. 51N - Set to be selective with downstream ground relaying. Where there is no ground relaying downstream, 51N should be selective with phase relaying. GP 16-02-01 permits relaxation of this requirement for large single motors (see GP 1602-01 for conditions that are acceptable). On four-wire systems with three CTs, 51N pickup must be above the maximum neutral current. On medium-voltage systems with low-resistance grounding, setting should be such that the LOWEST RELIABLE OPERATING CURRENT, which may be 1.5 times pickup for induction disc relays, is not more than 20% (one fifth) of the maximum ground fault current. On low-voltage systems setting should not be more than 40% of the maximum three phase fault level. See also DP XXX-D. 8.25

TRANSFORMER PRIMARY RELAY SETTINGS 50 - Relay must not “see" through the transformer. If it does, it will trip the transformer for faults on the secondary which should be cleared by the secondary relaying. Basis for setting is:

·

Set about 10% to 20% above the maximum fault level on the secondary, taking account of any dc offset to which the relay is sensitive. See Overreach in the DEFINITIONS section of this practice.

·

Set above transformer magnetizing inrush current. If more than one transformer on feeder, the setting must be above the inrush of all the transformers combined. 50GS - Use same basis as 50GS for Squirrel Cage Induction Motor Relay Settings. For a delta/star transformer, the 50GS in the primary is the first stage of the primary ground relaying.

This information is considered CONFIDENTIAL and shall not be released to or discussed with any persons except (a) employees of ExxonMobil Affiliates who have an appropriate research agreement with ExxonMobil Research and Engineering Company (EMRE), and (b) consultants, contractors, or employees of third parties with whom proper secrecy agreements have been executed with EMRE or such ExxonMobil Affiliates. ExxonMobil Research and Engineering Company

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51 - Basis for setting is:

8.26

·

When a feeder supplies two or more parallel transformers, each transformer that is not adequately protected by the feeder relay must have its own primary protection, which is normally 51 relaying supplied from bushing CTs mounted on the transformer primary. Adequate protection is defined in GP 16-02-01 (under Tapped Feeders) as operating in less than 2 seconds at 50% of the minimum secondary-side bolted phase-to-phase fault current.

·

Minimum pickup of the 51 relay protecting a tapped feeder should not be less than 125% of the sum of the forced cooled ratings (use self cooled rating for radial substations) of all the transformers on the feeder. Pickup setting of the relay providing “adequate protection" (defined above) for any given transformer is normally determined by coordination requirements. Per the USA National Electrical Code, pickup should be less than 400% of rated current if the rated impedance is more than 6%, up to 10%; pickup should be less than 600% for rated impedance no more than 6%.

·

On a tapped feeder or on any secondary-selective source feeder, must be selective with the highest set incomingbreaker 51-relay on the largest downstream transformer. Obviously this selectivity is required only up to the maximum secondary-side fault level. In the case of delta-wye transformers, the primary-side 51 relay must be selective with a dashed line drawn 16% higher in current (move 16% to right) than the largest downstream relay, as one primary line will “see" 16% more current than the two secondary lines for a phase-to-phase fault (see Figure 44).

·

On an untapped radial feeder, must be selective with highest-set downstream feeder device; on an untapped spotnetwork feeder, must be selective with highest set feeder relay, or bus tie relay if provided, or partial-differential relay if provided.

·

If pickup is not above maximum reacceleration current seen by the relay, the time delay should allow multiple step reacceleration taking account of any additive effect of the reacceleration steps on the relay.

·

Should be below transformer through-fault protection curve (for infrequent faults) to the extent practical, and should provide fault clearing in under 2 seconds for 50% of the minimum secondary-side bolted phase-to-phase fault current. If possible for a solidly-grounded delta-wye transformer, the primary curve shifted right by 1/0.58 (on current) should be below the through-fault protection curve over a reasonable secondary fault range.

SECONDARY-SELECTIVE AUTO-TRANSFER RELAY SETTINGS 27 - Transfer initiation relay, actuated for low voltage on one of the two upstream sources. Set as follows:

·

“Drop-out" should be at about 75% of system nominal voltage, and in any case below the lowest bus voltage obtained during motor reacceleration.

·

For substations closest to the source, time dial should be set to be selective with overcurrent relaying upstream to permit fault clearance and voltage recovery before initiating a transfer. Over the fault range for which the incomer 50 relay blocks transfer, coordination of the 27 with downstream overcurrent devices and incomer 51 relays is not necessary. However, coordination of the 27 with the incomer 51 (for the 51 to operate first) is desirable as backup for the 50 blocking function. See GP 16-02-01 under Documentation/Data for the reference on 27/51 coordination. Where the 50 blocking relay does not block the 27 over the range of practical fault currents, the 27 should coordinate with the incomer 51 relays. This usually results in a setting of one second, or slightly more, at zero volts. In the case of series transformation (see DP XXX-C) the downstream substation 27 relays may be set to be selective with the upstream 27 relays to permit the upstream substation to transfer and avoid transfer on the downstream substation. 27I - Healthy volts for transfer relay. This relay blocks transfer if voltages fail from both sources. It ensures that the infeed to which the load will be transferred is healthy. If there has been a voltage dip on the “healthy" incomer, the 27I will block initiation of a transfer until the volts have been restored for three seconds. The 27I is an instantaneous relay that operates time delay relay 96. On loss of incomer volts, 27I drops out which causes time delay relay 96 to pick up instantaneously and block transfer of the opposite bus. When voltage is restored, 27I picks up instantaneously, but the 96 time delay contacts are not closed for three seconds which blocks transfer for three seconds after restoration of voltage. Basis for setting is:

This information is considered CONFIDENTIAL and shall not be released to or discussed with any persons except (a) employees of ExxonMobil Affiliates who have an appropriate research agreement with ExxonMobil Research and Engineering Company (EMRE), and (b) consultants, contractors, or employees of third parties with whom proper secrecy agreements have been executed with EMRE or such ExxonMobil Affiliates. ExxonMobil Research and Engineering Company

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·

Dropout must be the same as or at higher voltage than dropout of the 27 relay.

·

After setting dropout, check pick-up which must be safely below the lowest expected sustained value of recovery voltage.

· Usual setting is dropout in the range of 80 to 90% volts. 27R - Residual voltage relay that delays closing of the tie breaker until the voltage of the “unhealthy" bus has decayed to the setting of 27R. This is required to prevent the high electrical and mechanical surges that would occur if the voltage either side of the tie breaker were 180 degrees out of phase and both at a high value at the time of tie closure. By setting 27R at 25% voltage, we attempt to limit the maximum torque imposed on the motor coupling to no more than four times the torques at motor rated output. Usual setting for relay is 25% volts with relay calibrated for dropout. This relay is instantaneous and will be required to operate at reduced frequency as the motors separated from the supply slow down. A conventional a-c instantaneous relay in this duty will have its dropout voltage decrease as the residualvoltage frequency decreases, and will also drop out as the sine wave passes through a zero when the frequency slows down (as also would a d-c relay powered from single-phase rectifier). To avoid this problem, we use a single element d-c relay powered from a three-phase rectifier. 50 - Transfer blocking relay. Prevents initiation of transfer when low voltage is due to fault downstream until fault is cleared. When the 50 relay picks up, it energizes time delay relay 97 which blocks transfer. When the 50 relay resets, provided the voltage has recovered enough to pick up the 27I relay, the 97 relay permits a transfer after a one-second delay. Basis for setting is: ·

Pickup should be about 10% above maximum motor contribution of motors on its own bus, taking account of relay sensitivity to dc offset, to avoid blocking transfer for a transformer bus-duct fault.

·

After setting relay, it should be tested for dropout to ensure that it will drop out at some current higher than the maximum load. 50N - Same function as 50. Operates the same 97 relay as the 50 relay. Basis for setting is:

·

Pickup must be below minimum ground fault current, with the usual setting being the minimum setting that will not falsely operate for the maximum (first half cycle) asymmetrical motor backfeed to a transformer bus-duct fault.

· ·

Pickup should be above neutral current on four-wire systems with only three CTs. Dropout must be above neutral current on four-wire systems with three CTs.

51G - Transformer neutral ground relay. Should be set to coordinate with incomer 51N. 8.27

GENERATOR RELAY SETTINGS

See DP XXX-B for generator relaying. Below are listed some typical settings for the relays: 32 - Power setting depends on type of driver. Set pickup at one fifth to one tenth of the minimum power required to “motor" the driver. Steam turbines require very sensitive reverse power pickup, often less than 0.5% of turbine rating , while diesel engines require pickup about 2.5% to 5% of engine rating, and gas turbines require pickup about 5% to 10% of turbine rating. Typical time setting is 10 seconds delay. 40 - Field Failure. One protection scheme uses one or two offset Impedance type (mho) relays with circles centered on negative reactance axis (completely below the resistance axis), where the larger circle diameter is set equal to the generator direct axis synchronous reactance, and the offset (of the circumference below the resistance axis) is set equal to half the generator direct axis transient reactance. Typical setting for time delay is 0.5 to 0.7 seconds. When a second, more sensitive mho relay is provided, it has the same offset, but the circle diameter is one per unit impedance, and there is no time delay. Another relay scheme has directional and undervoltage units in addition to one or two offset mho units. Consult relay application data for recommended settings for this type of scheme. 46 - Negative sequence. See NEGATIVE-SEQUENCE OVERCURRENT RELAYS (46) FOR GENERATOR PROTECTION under PROTECTIVE DEVICE TYPES AND APPLICATION above. Basically, the relay curve should be just below the generator (I2)2t curve, with (I2)2 pickup above the generator's continuous I2 capability. Often there is an alarm set below the tripping settings.

This information is considered CONFIDENTIAL and shall not be released to or discussed with any persons except (a) employees of ExxonMobil Affiliates who have an appropriate research agreement with ExxonMobil Research and Engineering Company (EMRE), and (b) consultants, contractors, or employees of third parties with whom proper secrecy agreements have been executed with EMRE or such ExxonMobil Affiliates. ExxonMobil Research and Engineering Company

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51V - Voltage-restrained or voltage-controlled overcurrent. See VOLTAGE-RESTRAINED (VOLTAGE-CONTROLLED) OVERCURRENT RELAYS (51V) under PROTECTIVE DEVICE TYPES AND APPLICATION above. The voltage setting for a voltage-controlled 51V should be below the lowest expected voltage during motor reacceleration (probably set just below about 60% voltage). Set the unrestrained (lowest pickup) curve to coordinate with the highest set downstream relay under the worst case for coordination. The coordination should account for the effect of generator decrement on the operating time of the downstream and 51V relays per IEE Transactions IGA March/April 1965, pp. 130-139, “Allowing for Decrement and Fault Voltage in Industrial Relaying". The 51V relay should be set with the minimum safe discrimination interval practical for the maximum fault current through the 51V at zero voltage, and for the least current that would flow simultaneously through the highest-set downstream relay. This condition is usually obtained when the generator with the 51V is the only source of fault current. The setting should be checked for proper operation under emergency operation conditions such as motor reacceleration and stable transient swings for which tripping should not occur. 59 - Overvoltage. Check insulation design withstand with manufacturer. If such a relay is fitted, we recommend that it be connected to alarm only. Typical setting 120% with time delay of 2 seconds. 64F - Rotor Ground Fault. Connect to alarm only. Typical setting 1 milliampere. 8.28

GENERATOR SEPARATION RELAY SETTINGS 67 - Directional overcurrent relay looking towards utility source. May have contacts in series with a voltage relay. Current and voltage settings should be roughly equal to those values that would occur for 50% or lower voltage at utility substation with the in-plant generator connected. Time setting should preferably be above the utility relaying but must be less than that which would cause instability of the in-plant generation. Typical settings are in the 0.3 to 1 second range. 81 - Frequency. Settings should be above value that would cause problems with electrical plant, such as tripping of motors by overload relays and inability of in-plant generation to sustain itself due to the slowing down of the auxiliaries. Typical values for the latter are 5% under frequency. Setting may be above frequency relay settings for load shedding in the plant if these relays are blocked when operating in parallel with the utility. Ideally frequency setting for separation of inplant generation should be below the utility company's load shedding and network fragmentation frequency relays to give the utility an opportunity to rectify the problem. More sophisticated relaying may be applied by using rate of change of frequency relays in addition to absolute frequency relays for separation of in-plant generation. A large integrated utility network extending over a country or maybe even a continent cannot change the frequency very fast due to the enormous inertia of the sum of all the synchronous machine connected. Therefore, if the frequency changes rapidly, it is a sure sign that the utility network has become fragmented, which spells problems. If possible, obtain data from the utility to determine settings for rate of change of frequency relays. If not, determine from past incidents actual frequency performance during normal operation and during system disturbances.

8.29 ç

SPOT NETWORK RELAY SETTINGS

See the guidelines for applying relaying in spot networks earlier in this Design Practice that appear under the heading SPOT NETWORK SUBSTATION PROTECTION, in the section entitled BASIC DESIGN CONSIDERATIONS (Refer to Figure 47). 67 - The transformer secondary 67 relay must be selective with upstream feeder relaying of upstream buses to permit upstream faults to be cleared by upstream relaying and not trip one side of the spot network back feeding the fault. The 67 must operate before the transformer secondary 51 relay for upstream faults. The 67 relay should be set so that it does not operate due to the no-load capacitive current which may flow if all load is lost. 67N - This relay must detect ground faults between the transformer and the main breaker. Due to the high CT ratio on main breakers, auxiliary CT's are sometimes used to connect this relay. Care must be exercised in selecting this auxiliary CT to prevent excessive burden on the phase CT. Transformer neutral current is typically used to "polarize" the relay to trip in the correct direction. 51N - The 51N is residually connected to the bus partial differential protection on spot networks with tie breakers. It must be set to coordinate with the feeder ground relays below and the transformer neutral ground relay 51G above. Like the 67N, this relay sometimes is connected using an auxiliary CT. Care must be exercised in selecting this auxiliary CT to prevent excessive burden on the phase CT.

This information is considered CONFIDENTIAL and shall not be released to or discussed with any persons except (a) employees of ExxonMobil Affiliates who have an appropriate research agreement with ExxonMobil Research and Engineering Company (EMRE), and (b) consultants, contractors, or employees of third parties with whom proper secrecy agreements have been executed with EMRE or such ExxonMobil Affiliates. ExxonMobil Research and Engineering Company

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51 - The bus overcurrent partial differential relay must be selective with upstream 51 relays to prevent unnecessary tripping of other substations connected in parallel. The 51 must also coordinate with the feeder overcurrent relays on both buses in the spot network. The coordination of this relay must take into account that it will see fault current from both the transformer supplying the bus and through the tie breaker from the other transformer. 87TN - Transformer restricted earth fault relays can be used to replace the 67N relay protecting the zone between the transformer secondary main breaker and the transformer, with the added benefit of protecting the transformer secondary winding. The residual of the main breaker CT's and a transformer neutral CT are required by this relay. Like the 67N, this relay sometimes is connected using an auxiliary CT. Care must be exercised in selecting this auxiliary CT to prevent excessive burden on the phase CT. Improper connection of this relay or auxiliary CT will cause tripping for out-of-zone faults. This condition will not be revealed by three phase balanced load currents. 8.30

PARTIAL DIFFERENTIAL RELAY SETTINGS 51- See PARTIAL DIFFERENTIAL PROTECTION above in the section entitled BASIC DESIGN CONSIDERATIONS. For spot networks, relay must coordinate with the downstream feeder relaying with both sources feeding the fault.

8.31

RESTRICTED EARTH FAULT PROTECTION

See RESTRICTED EARTH FAULT PROTECTION above in the section entitled BASIC DESIGN CONSIDERATIONS. Select type of relay to be used, and follow manufacturer's setting recommendations.

This information is considered CONFIDENTIAL and shall not be released to or discussed with any persons except (a) employees of ExxonMobil Affiliates who have an appropriate research agreement with ExxonMobil Research and Engineering Company (EMRE), and (b) consultants, contractors, or employees of third parties with whom proper secrecy agreements have been executed with EMRE or such ExxonMobil Affiliates. ExxonMobil Research and Engineering Company

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Table 1 I.E.C. Recommended Fuse Ratings For Low Voltage AMPS

AMPS

2

100*

4

125

6

160*

8

200

10

250*

12

315

16

400*

20

500*

25

630*

32*

800*

40

1000*

50

1250*

63* 80

* - Vendor typical fuse holder rating break points. Table 2 Typical Current Transformer Ratios SINGLE RATIO (amperes)

DOUBLE RATIO WITH SERIES - PARALLEL PRIMARY WINDINGS (amperes)

DOUBLE RATIO WITH TAPS IN SECONDARY WINDING (amperes)

10/5

25 x 50/5

25/50/5

15/5

50 x 100/5

50/100/5

25/5

100 x 200/5

100/200/5

40/5

200 x 400/5

200/400/5

50/5

400 x 800/5

300/600/5

75/5

600 x 1200/5

400/800/5

100/5

1000 x 2000/5

600/1200/5

200/5

2000 x 4000/5

1000/2000/5

300/5

1500/3000/5

400/5

2000/4000/5

600/5 800/5 1200/5 1500/5 2000/5 3000/5 4000/5 5000/5 6000/5 8000/5 12,000/5 This information is considered CONFIDENTIAL and shall not be released to or discussed with any persons except (a) employees of ExxonMobil Affiliates who have an appropriate research agreement with ExxonMobil Research and Engineering Company (EMRE), and (b) consultants, contractors, or employees of third parties with whom proper secrecy agreements have been executed with EMRE or such ExxonMobil Affiliates. ExxonMobil Research and Engineering Company

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9.1

ELECTRICAL POWER FACILITIES

October, 2004

IEEE STANDARD ELECTRICAL DEVICE FUNCTION NUMBERS

DEVICE NUMBERS

The device numbers shown by Table 3 are covered in IEEE Standard C37.2. Table 3 IEEE Standard Device Numbers DEVICE NUMBER

DEFINITION AND FUNCTION

1

5

Master Element is the initiating device, such as a control switch, voltage relay, float switch, etc., which serves either directly or through such permissive devices as protective and time-delay relays to place an equipment in or out of operation. Time-Delay Starting or Closing Relay is a device which functions to give a desired amount of time delay before or after any point or operation in a switching sequence or protective relay system, except as specifically provided by device functions 62 and 79 described later. Checking or Interlocking Relay is a device which operates in response to the position of a number of other devices, or to a number of predetermined conditions in an equipment to allow an operating sequence to proceed, to stop, or to provide a check of the position of these devices or of these conditions for any purpose. Master Contactor is a device, generally controlled by Device No. 1 or equivalent, and the necessary permissive and protective devices, which serves to make and break the necessary control circuits to place an equipment into operation under the desired conditions and to take it out of operation under other or abnormal conditions. Stopping Device functions to place and hold an equipment out of operation.

6

Starting Circuit Breaker is a device whose principal function is to connect a machine to its source of starting voltage.

7

Anode Circuit Breaker is one used in the anode circuits of a power rectifier for the primary purpose of interrupting the rectifier circuit if an arc back should occur. Control Power Disconnecting Device is a disconnecting device - such as a knife switch, circuit breaker or pullout fuse block used for the purpose of connecting and disconnecting, respectively, the source of control power to and from the control bus or equipment. Note: Control power is considered to include auxiliary power which supplies such apparatuses as small motors and heaters. Reversing Device is used for the purpose of reversing a machine field or for performing any other reversing functions.

2 3 4

8

9

11

Unit Sequence Switch is used to change the sequence in which units may be placed in and out of service in multiple-unit equipment. Reserved for future application.

12

Overspeed Device is usually a direct-connected speed switch which functions on machine overspeed.

13

Synchronous-Speed Device, such as a centrifugal-speed switch, a slip-frequency relay, a voltage relay, an undercurrent relay or any type of device, operates at approximately synchronous speed of a machine. Underspeed Device functions when the speed of a machine falls below a predetermined value.

10

14 15 16 17

18 19 20

21 22

Speed or Frequency Matching Device functions to match and hold the speed or the frequency of a machine or of a system equal to, or approximately equal to, that of another machine, source or system. Reserved for future application. Shunting or Discharge Switch serves to open or to close a shunting circuit around any piece of apparatus (except a resistor), such as a machine field, a machine armature, a capacitor or a reactor. Note: This excludes devices which perform such shunting operations as may be necessary in the process of starting a machine by Devices 6 to 42, or their equivalent, and also excludes Device 73 function which serves for the switching of resistors. Accelerating or Decelerating Device is used to close or to cause the closing of circuits which are used to increase or to decrease the speed of a machine. Starting-to-Running Transition Contactor is a device which operates to initiate or cause the automatic transfer of a machine from the starting to the running power connection. Electrically Operated Valve is a solenoid- or motor-operated valve which is used in a vacuum, air, gas, oil, water, similar, lines. Note: The function of the valve may be indicated by the insertion of descriptive words, such as “Brake" or “Pressure Reducing" in the function name, such as “Electrically Operated Brake Valve." Distance Relay is a device which functions when the circuit admittance, impedance, or reactance increases or decreases beyond predetermined limits. Equalizer Circuit Breaker is a breaker which serves to control or to make and break the equalizer or the current-balancing connections for a machine field, or for regulating equipment, in a multiple-unit installation.

This information is considered CONFIDENTIAL and shall not be released to or discussed with any persons except (a) employees of ExxonMobil Affiliates who have an appropriate research agreement with ExxonMobil Research and Engineering Company (EMRE), and (b) consultants, contractors, or employees of third parties with whom proper secrecy agreements have been executed with EMRE or such ExxonMobil Affiliates. ExxonMobil Research and Engineering Company

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IEEE Standard Electrical Device Function Numbers (Cont) DEVICE NUMBER

DEFINITION AND FUNCTION

23

Temperature Control Device functions to raise or to lower the temperature of a machine or other apparatus, or of any medium, when its temperature falls below, or rises above, a predetermined value. Note: An example is a thermostat which switches on a space heater in a switchgear assembly when the temperature falls to a directed value as distinguished from a device which is used to provide automatic temperature regulation between close limits and would be designated as 90T. Volts per Hertz Device operates on the ratio of voltage to frequency.

24

27

Synchronizing or Synchronism-Check Device operates when two a-c circuits are within the desired limits of frequency, phase angle or voltage, to permit or to cause the paralleling of these two circuits. Apparatus Thermal Device functions when the temperature of the shunt field or the amortisseur winding of a machine, or that of a load limiting or load shifting resistor or of a liquid or other medium exceeds a predetermined value; or if the temperature of the protected apparatus, such as a power rectifier, or of any medium decreases below a predetermined value. Undervoltage Relay is a device which functions on a given value of undervoltage.

28

Flame Detector monitors the presence of the pilot or main flame in such apparatus as a gas turbine or a steam boiler.

29

Isolating Contactor is used expressly for disconnecting one circuit from another for the purposes of emergency operation, maintenance, or test. Annunciator Relay is a non-automatically reset device which gives a number of separate visual indications upon the functioning of protective devices, and which may also be arranged to perform a lockout function. Separate Excitation Device connects a circuit such as the shunt field of a synchronous converter to a source of separate excitation during the starting sequence; or one which energizes the excitation and ignition circuits of a power rectifier. Directional Power Relay is one which functions on a desired value of power flow in a given direction, or upon reverse power resulting from arc back in the anode or cathode circuits of a power rectifier. Position Switch makes or breaks contact when the main device or piece of apparatus, which has no device function number, reaches a given position. Motor-Operated Sequence Switch is a multi-contact switch which fixes the operating sequence of the major devices during starting and stopping, or during other sequential switching operations. Brush-Operating or Slip-Ring Short-Circuiting Device is used for raising, lowering, or shifting the brushes of a machine, or for short-circuiting its slip rings, or for engaging or disengaging the contacts of a mechanical rectifier. Polarity Device operates or permits the operation of another device on a predetermined polarity only.

25 26

30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49

Undercurrent or Underpower Relay is a device which functions when the current or power flow decreases below a predetermined value. Bearing Protective Device is one which functions on excessive bearing temperature, or on other abnormal mechanical conditions, such as undue wear, which may eventually result in excessive bearing temperature. Mechanical Condition Monitor functions on the occurrence of an abnormal mechanical condition. Field Relay is a device that functions on a given or abnormally low value or failure of machine field current, or on an excessive value of the reactive component of armature current in an a-c machine indicating abnormally low field excitation. Field Circuit Breaker is a device which functions to apply, or to remove, the field excitation of a machine. Running Circuit Breaker is a device whose principal function is to connect a machine to its source of running voltage after having been brought up to the desired speed on the starting connection. Manual Transfer or Selector Device transfers the control circuits so as to modify the plan of operation of the switching equipment or of some of the devices. Unit Sequence Starting Relay is a device which functions to start the next available unit in a multiple-unit equipment on the failure or on the non-availability of the normally preceding unit. Atmospheric Condition Monitor functions on the occurrence of an abnormal atmospheric condition. Reverse-Phase or Phase-Balance Current Relay is a device which functions when the polyphase currents are of reversephase sequence, or when the polyphase currents are unbalanced or contain negative phase-sequence components above a given amount. Phase-Sequence Voltage Relay is a device which functions upon a predetermined value of polyphase voltage in the desired phase sequence. Incomplete Sequence Relay is a device which returns the equipment to the normal, or off, position and locks it out if the normal starting, operating or stopping sequence is not properly completed within a predetermined time. Machine or Transformer Thermal Relay is a device which functions when the temperature of an a-c machine armature, or of the armature or other load carrying winding or element of a d-c machine, or converter or power rectifier or power transformer (including a power rectifier transformer) exceeds a predetermined value.

This information is considered CONFIDENTIAL and shall not be released to or discussed with any persons except (a) employees of ExxonMobil Affiliates who have an appropriate research agreement with ExxonMobil Research and Engineering Company (EMRE), and (b) consultants, contractors, or employees of third parties with whom proper secrecy agreements have been executed with EMRE or such ExxonMobil Affiliates. ExxonMobil Research and Engineering Company

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IEEE Standard Electrical Device Function Numbers (cont) DEVICE NUMBER

DEFINITION AND FUNCTION

50

58

Instantaneous Overcurrent or Rate-of-Rise Relay is a device which functions instantaneously on an excessive value of current, or on an excessive rate of current rise, thus indicating a fault in the apparatus or circuit being protected. A-C Time Overcurrent Relay is a device which either a definite or inverse time characteristic which functions when the current in an a-c circuit exceeds a predetermined value. A-C Circuit Breaker is a device which is used to close and interrupt an a-c power circuit under normal conditions or to interrupt this circuit under fault or emergency conditions. Exciter or D-C Generator Relay is a device which forces the d-c machine field excitation to build up during starting or which functions when the machine voltage has built up to a given value. High-Speed D-C Circuit Breaker is a circuit breaker which starts to reduce the current in the main circuit in 0.01 second or less, after the occurrence of the d-c overcurrent or the excessive rate of current rise. Power Factor Relay is a device which operates when the power factor in an a-c circuit becomes above or below a predetermined value. Field Application Relay is a device which automatically controls the application of the field excitation to an a-c motor at some predetermined point in the slip cycle. Short-Circuiting or Grounding Device is a power or stored energy operated device which functions to short-circuit or to ground a circuit in response to automatic or manual means. Power Rectifier Misfire Relay is a device which functions if one or more of the power rectifier anodes fails to fire.

59

Overvoltage Relay is a device which functions on a given value of overvoltage.

60

Voltage Balance Relay is a device which operates on a given difference in voltage between two circuits.

61

Current Balance Relay is a device which operates on a given difference in current input or output of two circuits.

62

Time-Delay Stopping or Opening Relay is a time-delay device which serves in conjunction with the device which initiates the shutdown, stopping, or opening operation in an automatic sequence. Liquid or Gas Pressure, Level, or Flow Relay is a device which operates on given values of liquid or gas pressure, flow or level, or on a given rate of change of these values. Ground Detector Relay is a relay that operates on failure of machine or other apparatus insulation to ground. Note: This function is not applied to a device connected in the secondary circuit of current transformers in a normally grounded power system. Governor is the equipment which controls the gate or valve opening of a prime mover.

51 52 53 54 55 56 57

63 64 65 66 67 68 69 70 71 72 73 74 75 76

Notching or Jogging Device functions to allow only a specified number of operations of a given device, or equipment, or a specified number of successive operations within a given time of each other. It also functions to energize a circuit periodically, or which is used to permit intermittent acceleration or jogging of a machine at low speeds for mechanical positioning. A-C Directional Overcurrent Relay is a device which functions on a desired value of a-c overcurrent flowing in a predetermined direction. Blocking Relay is a device which initiates a pilot signal for blocking of tripping on external faults in a transmission line or in other apparatus under predetermined conditions, or cooperates with other devices to block tripping or to block reclosing on an out-of-step condition or on power swings. Permissive Control Device is generally a two-position, manually operated switch which in one position permits the closing of a circuit breaker, or the placing of an equipment into operation, and in the other position prevents the circuit breaker or the equipment from being operated. Electrically Operated Rheostat is a rheostat which is used to vary the resistance of a circuit in response to some means of electrical control. Level Switch is a switch which operates on given values, or on a given rate of change of level. D-C Circuit Breaker is used to close and interrupt a d-c power circuit under normal conditions or to interrupt this circuit under fault or emergency conditions. Load-Resistor Contactor is used to shunt or insert a step of load limiting, shifting, or indicating resistance in a power circuit, or to switch a space heater in circuit, or to switch a light, or regenerative, load resistor of a power rectifier or other machine in and out of circuit. Alarm Relay is a device other than an annunciator, as covered under Device No. 30, which is used to operate, or to operate in connection with, a visual or audible alarm. Position Changing Mechanism is the mechanism which is used for moving a removable circuit breaker unit to and from the connected, disconnected, and test positions. D-C Overcurrent Relay is a device which functions when the current in a d-c circuit exceeds a given value.

This information is considered CONFIDENTIAL and shall not be released to or discussed with any persons except (a) employees of ExxonMobil Affiliates who have an appropriate research agreement with ExxonMobil Research and Engineering Company (EMRE), and (b) consultants, contractors, or employees of third parties with whom proper secrecy agreements have been executed with EMRE or such ExxonMobil Affiliates. ExxonMobil Research and Engineering Company

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IEEE Standard Electrical Device Function Numbers (Cont) DEVICE NUMBER

DEFINITION AND FUNCTION

77

Pulse Transmitter is used to generate and transmit pulses over a telemetering or pilot-wire circuit to the remote indicating or receiving device.

78

Phase Angle Measuring or Out-of-Step Protective Relay is a device which functions at a predetermined phase angle between two voltages or between two currents or between voltage and current.

79

A-C Reclosing Relay is a device which controls the automatic reclosing and locking out of an a-c circuit interrupter.

80

Flow Switch is a switch which operates on given values, or on a given rate of change of flow.

81

Frequency Relay is a device which functions on a predetermined value of frequency - either under or over or on normal system frequency - or rate of change of frequency.

82

D-C Reclosing Relay is a device which controls the automatic closing and reclosing of a d-c circuit interrupter, generally in response to load circuit conditions.

83

Automatic Selective Control or Transfer Relay is a device which operates to select automatically between certain sources or conditions in an equipment, or performs a transfer operation automatically.

84

Operating Mechanism is the complete electrical mechanism or servo-mechanism, including the operating motor, solenoids, position switches, etc., for tap changer, induction regulator or any piece of apparatus which has no device function number.

85

Carrier, or Pilot-Wire, Receiver Relay is a device which is operated or restrained by a signal used in connection with carriercurrent or d-c pilot-wire fault directional relaying.

86

Locking-Out Relay is an electrically operated hand or electrically reset device which functions to shut down and hold an equipment out of service on the occurrence of abnormal conditions.

87

Differential Protective Relay is a protective device which functions on a percentage or phase angle or other quantitative difference of two currents or of some other electrical quantities.

88

Auxiliary Motor, or Motor Generator is one used for operating auxiliary equipment such as pumps, blowers, exciters, rotating magnetic amplifiers, etc.

89

Line Switch is used as a disconnecting or isolating switch in an a-c or d-c power circuit, when this device is electrically operated or has electrical accessories, such as an auxiliary switch, magnetic lock, etc.

90

Regulating Device functions to regulate a quantity, or quantities, such as voltage, current, power, speed, frequency, temperature, and load, at a certain value or between certain limits for machines, tie lines or other apparatus.

91

Voltage Directional Relay is a device which operates when the voltage across an open circuit breaker or contactor exceeds a given value in a given direction.

92

Voltage and Power Directional Relay is a device which permits or causes the connection of two circuits when the voltage difference between them exceeds a given value in a predetermined direction and causes these two circuits to be disconnected from each other when the power flowing between them exceeds a given value in the opposite direction.

93

Field Changing Contactor functions to increase or decrease in one step the value of field excitation on a machine.

94

Tripping, or Trip-Free, Relay is a device which functions to trip a circuit breaker, contactor, or equipment, or to permit immediate tripping by other devices; or to prevent immediate reclosure of a circuit interrupter, in case it should open automatically even though its closing circuit is maintained closed.

95 to 99

Used only for specific applications on individual installations where none of the assigned numbered functions from 1 to 94 is suitable. Note: The following sections entitled “Suffix Letters", “Suffix Numbers", and “Devices Performing More than One Function" have not been updated. For the most up to date coverage of this material, see IEEE Standard C37.2.

9.2

SUFFIX LETTERS

Suffix letters are used with device function numbers for various purposes. In order to prevent possible conflict, any suffix letter used singly, or any combination of letters, denotes only one word or meaning in an individual equipment. All other words should use the abbreviations as contained in American Standard Z32.12-1950, or latest revision thereof, or should use some other

This information is considered CONFIDENTIAL and shall not be released to or discussed with any persons except (a) employees of ExxonMobil Affiliates who have an appropriate research agreement with ExxonMobil Research and Engineering Company (EMRE), and (b) consultants, contractors, or employees of third parties with whom proper secrecy agreements have been executed with EMRE or such ExxonMobil Affiliates. ExxonMobil Research and Engineering Company

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October, 2004

distinctive abbreviation, or be written out in full each time they are used. Furthermore, the meaning of each single suffix letter, or combination of letters, should be clearly designated in the legend on the drawings or publications applying to the equipment: The following suffix letters generally form part of the device function designation and thus are written directly behind the device number, such as 23X, 90V, or 52BT. These letters denote separate auxiliary devices, such as: X} Y}

-

Auxiliary relay*

R

-

Raising relay

L

-

Lowering relay

O

-

Opening relay

C

-

Closing relay

Z}

*Note: In the control of a circuit breaker with so-called X-Y relay control scheme, the X relay is the device whose main contacts are used to energize the closing coil and the contacts of the Y relay provide the anti-pump feature for the circuit breaker. CS

-

Control switch

CL

-

“A" auxiliary-switch relay

OP

-

“B" auxiliary-switch relay

U PB

“Up" position-switch relay -

Push button

These letters indicate the condition or electrical quantity to which the device responds, or the medium in which it is located, such as: A

-

Air, or amperes

C

-

Current

E

-

Electrolyte

F

-

Frequency, or flow

L

-

Level, or liquid

P

-

Power, or pressure

PF

-

Power factor

Q

-

Oil

S

-

Speed

T

-

Temperature

V

-

Voltage, volts, or vacuum

VAR

-

Reactive power

W

-

Water, or watts

These letters denote the location of the main device in the circuit, or the type of circuit in which the device is used or the type of circuit or apparatus with which it is associated, when this is necessary, such as: A

-

Alarm or auxiliary power

This information is considered CONFIDENTIAL and shall not be released to or discussed with any persons except (a) employees of ExxonMobil Affiliates who have an appropriate research agreement with ExxonMobil Research and Engineering Company (EMRE), and (b) consultants, contractors, or employees of third parties with whom proper secrecy agreements have been executed with EMRE or such ExxonMobil Affiliates. ExxonMobil Research and Engineering Company

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AC

-

Alternating current

AN

-

Anode

B

-

Battery, or blower, or bus

BK

-

Bypass

BT

-

Bus tie

C

-

Capacitor, or condenser, compensator, or carrier current

CA

-

Cathode

DC

-

Direct current

E

-

Exciter

F

-

Feeder, or field, or filament

G

-

Generator, or ground** (see note below)

H

-

Heater, or housing

L

-

Line

M

-

Motor, or metering

N

-

Network, or neutral** (see note below)

P

-

Pump

R

-

Reactor, or rectifier

S

-

Synchronizing

T

-

Transformer, or test, or thyraton

TH

-

Transformer (high-voltage side)

TL

-

Transformer (low-voltage side)

TM

-

Telemeter

U

-

Unit

October, 2004

** Suffix “N" is generally used in preference to “G" for devices connected in the secondary neutral of current transformers, or in the secondary of a current transformer whose primary winding is located in the neutral of a machine or power transformer, except in the case of transmission line relaying, where the suffix “G" is more commonly used for those relays which operate on ground faults. These letters denote parts of the main device: Many of these do not form part of the device number, and should be written directly below the device number, such as 20 43 or LS A BB

-

Bucking bar (for high speed d-c circuit breaker)

BK

-

Brake

C

-

Coil, or condenser, or capacitor

CC

-

Closing coil

HC

-

Holding coil

IS

-

Inductive shunt

L

-

Lower operating coil

M

-

Operating motor

This information is considered CONFIDENTIAL and shall not be released to or discussed with any persons except (a) employees of ExxonMobil Affiliates who have an appropriate research agreement with ExxonMobil Research and Engineering Company (EMRE), and (b) consultants, contractors, or employees of third parties with whom proper secrecy agreements have been executed with EMRE or such ExxonMobil Affiliates. ExxonMobil Research and Engineering Company

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MF

-

Fly-ball motor

ML

-

Load-limit motor

MS

-

Speed adjusting, or synchronizing, motor

S

-

Solenoid

TC

-

Trip coil

U

-

Upper operating coil

V

-

Valve

October, 2004

All auxiliary contacts and limit switches for such devices and equipment as circuit breakers, contactors, valves, and rheostats. These are designated as follows: a

-

Auxiliary switch, open when the main device is in the de-energized or non-operated position.

b

-

Auxiliary switch, closed when the main device is in the de-energized or non-operated position.

aa Auxiliary switch, open when the operating mechanism of the main device is in the de-energized or nonoperated position. bb Auxiliary switch, closed when the operating mechanism of the main device is in the de-energized or nonoperating position. e, f, h, etc., ab, ac, ad, etc., or ba, bc, bd, etc., are special auxiliary switches other than a, b, aa, and bb. Lower-case (small) letters are to be used for the above auxiliary switches. Note: If several similar auxiliary switches are present on the same device, they should be designated numerically 1, 2, 3, etc., when necessary. LC Latch-checking switch, closed when the circuit breaker-mechanism linkage is relatched after an opening operation of the circuit breaker. LS

-

Limit switch.

These letters cover all other distinguishing features or characteristics or conditions, not specifically described above, which serve to describe the use of the device or its contacts in the equipment such as: A

-

Accelerating, or automatic

B

-

Blocking, or backup

C

-

Close, or cold

D

-

Decelerating, detonate, or down

E

-

Emergency

F

-

Failure, or forward

H

-

Hot, or high

HR

-

Hand reset

HS

-

High speed

IT

-

Inverse time

L

-

Left, or local, or low, or lower, or leading

M

-

Manual

OFF

-

Off

ON

-

On

O

-

Open

P

-

Polarizing

This information is considered CONFIDENTIAL and shall not be released to or discussed with any persons except (a) employees of ExxonMobil Affiliates who have an appropriate research agreement with ExxonMobil Research and Engineering Company (EMRE), and (b) consultants, contractors, or employees of third parties with whom proper secrecy agreements have been executed with EMRE or such ExxonMobil Affiliates. ExxonMobil Research and Engineering Company

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R

-

Right, or raise, or reclosing, or receiving, or remote, or reverse

S

-

Sending, or swing

T

-

Test, or trip, or trailing

TDC

-

Time-delay closing

TDO

-

Time-delay opening

U

-

Up

9.3

October, 2004

SUFFIX NUMBERS

If two or more devices with the same function number and suffix letter (if used) are present in the same equipment, they may be distinguished by numbered suffixes as for example 52X-1, 52X-2, and 52X-3, when necessary. 9.4

DEVICES PERFORMING MORE THAN ONE FUNCTION

If one device performs two relatively important functions in an equipment so that it is desirable to identify both of these functions, this may be done by using a double function number and name such as:

· 9.5

27-59 undervoltage and overvoltage relay PER UNIT SYSTEM

9.5.1

Definitions:

kVAB

=

Base kVA (three phase)

kVB

=

Base kV (line to line)

IB

=

Base Current

ZB

=

Base Impedance

Zpu

=

Per Unit Impedance

Z

=

Impedance in Ohms

Note: To convert the impedances in an electrical system to a consistent set of per unit impedances, select the base voltages on either side of a transformer such that their ratio is the same as the nominal voltage ratio of the transformer; and select one base kVA for the entire system. With rare exception, the base voltage and the winding nominal voltage are the same. All impedances on a given side of a transformer must be per-unitized on the base kV on that side of the transformer, and all equipment in the system, including the transformers, must be per-unitized on the base kVA of the entire system. In the rare event the transformer voltage ratio and base-voltages ratio are equal but the rated voltage does not equal the base voltage (e.g., 132 kV/13.2kV = 138kV/13.8kV, but 132kV is not the base voltage), the per unit impedance based on rated voltages must be multiplied by the square of the ratio of rated voltage to base voltage. See formulas below for converting per unit quantities to new kVA and kV bases.

This information is considered CONFIDENTIAL and shall not be released to or discussed with any persons except (a) employees of ExxonMobil Affiliates who have an appropriate research agreement with ExxonMobil Research and Engineering Company (EMRE), and (b) consultants, contractors, or employees of third parties with whom proper secrecy agreements have been executed with EMRE or such ExxonMobil Affiliates. ExxonMobil Research and Engineering Company

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Basic Formulas: kVA B

IB =

ZB =

3 kVB

3 IB

ZW =

(1)

amperes

1000 kVB

Zpu =

9.6

October, 2004

ohms =

1000 (kVB )2 ohms kVA B

ZW ZW (kVA B ) = ZB 1000 (kVB )2

10 (kVB )2 x % Z kVA B

(2)

(3)

(4)

CONVERSIONS AND CALCULATIONS

Converting per unit to percent: % Z = 100 Zpu

(5)

Converting Zpu to New Voltage Base: ( Zpu ) 2 = ( Zpu )1

(kVB1)2 (kVB2 )2

(6)

Converting Zpu to New kVA Base: ( Zpu ) 2 = ( Zpu )1

(kVA )B2 (kVA )B1

(7)

Given a single-phase grounding transformer with a secondary-to-primary voltage ratio of (kV)S/(kV)P, the relationship between a secondary-side resistor, (R)S and its reflection (R)P into the primary (e.g., into the neutral of a generator) is: (RW ) s = (RW ) p

(kVs )2 (kVp )2

(8)

Determining Burden Impedance (Z):

Z = where: VA V I

= = =

( VA ) I2

=

( V )2 ohms VA

(9)

volt-ampere burden at specified V or I. voltage at which burden is specified. current at which burden is specified.

Determining New Short Time Relay Coil Rating

This information is considered CONFIDENTIAL and shall not be released to or discussed with any persons except (a) employees of ExxonMobil Affiliates who have an appropriate research agreement with ExxonMobil Research and Engineering Company (EMRE), and (b) consultants, contractors, or employees of third parties with whom proper secrecy agreements have been executed with EMRE or such ExxonMobil Affiliates. ExxonMobil Research and Engineering Company

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(Approximate - do not use continuous rating): t1 t2

I2 = I1

where: I2 I1

= =

(10)

thermal rating for t2 time thermal rating for t1 time

Converting kVA to Amperes (1): I=

where: kVA = kV =

kVA 3 kV

amperes

(11)

three-phase power rated potential, kilovolts

Determining Distance Relay Apparent Impedance, ZR, Due to Infeed Current Z ZD IR

IR + ID ID

Relay Location

Fault Location

ZR = Z + where: ZR

=

Z ZD ID IR

= = = =

ID ZD relay ohms IR

(12)

apparent primary impedance sensed by the distance relay, based on (VR)LN at the relay location, divided by IR, for a bolted three-phase at other end. series line-impedance from relay location to fault. portion of line impedance, Z, through which ID + IR is flowing. infeed current current in relaying current transformer primary

Decay of D-C Component

it = Io where: it Io e t

= = = =

T

=

L R

= =

t T e

(13)

d-c component of current at time t d-c component of current at time zero base of Napierian logarithms = 2.71828... time at which d-c component is being calculated L Time Constant = R inductance of circuit resistance of circuit

This information is considered CONFIDENTIAL and shall not be released to or discussed with any persons except (a) employees of ExxonMobil Affiliates who have an appropriate research agreement with ExxonMobil Research and Engineering Company (EMRE), and (b) consultants, contractors, or employees of third parties with whom proper secrecy agreements have been executed with EMRE or such ExxonMobil Affiliates. ExxonMobil Research and Engineering Company

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Appendix A - Symbols

G

Generator

Coil

XX

Protective or Control Device

Bus Duct

XX XX

Protective or Control Device

Indicating Light

Drawout

Pothead

Push Button

Outdoor Power Circuit Breaker

Protective Device

Current Transformer

Zero Sequence Current Transformer

Delta Winding

Diode

Diode

Power Transformer

Disconnect Switch

"OR"Logic

"AND" Logic

AND with 2 inputs negated

Thyristor

This information is considered CONFIDENTIAL and shall not be released to or discussed with any persons except (a) employees of ExxonMobil Affiliates who have an appropriate research agreement with ExxonMobil Research and Engineering Company (EMRE), and (b) consultants, contractors, or employees of third parties with whom proper secrecy agreements have been executed with EMRE or such ExxonMobil Affiliates. ExxonMobil Research and Engineering Company

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Appendix A - Symbols (cont) Resistor

Link

Delta-Wye with Secondary Neutral Resistance Ground

Surge Protector

Earth

Wye Connected with Neutral Solidly Grounded

Fuse

Transfer Switch

Manual Selector Switch Normally Open Contact Normally Closed Contact

Disconnect Switch and Fuse

Drawout Metal-Clad Contactor

Circuit Breaker

Drawout Indoor Metal-Clad Circuit Breaker

Current Limiting Circuit Breaker Combination Starter

Lightning Arrestor

Capacitor Fused Combination Starter Battery

This information is considered CONFIDENTIAL and shall not be released to or discussed with any persons except (a) employees of ExxonMobil Affiliates who have an appropriate research agreement with ExxonMobil Research and Engineering Company (EMRE), and (b) consultants, contractors, or employees of third parties with whom proper secrecy agreements have been executed with EMRE or such ExxonMobil Affiliates. ExxonMobil Research and Engineering Company

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Appendix A - Symbols (cont) Three Winding Transformer with Automatic On-Load Tap Changer

Resistor

Thermal Elemebt

Power Transformer

Connection

Reactor

Three Winding Transformer with Automatic On-Load Tap Changer

Reactor

Wye Winding

Autotransformer

Autotransformer

M

Fused Disconnect Switch

Circuit Breaker Combination Starter

Three Winding Transformer

Power Transformer

Potential Transformer

Power Transformer with Automatic On-Load Tap Changer

Motor

~

=

~

=

=

Battery Chager or Restifier

~

Inverter

~

A-C Voltage Stabilizer

=

D-C Voltage Stabilizer

This information is considered CONFIDENTIAL and shall not be released to or discussed with any persons except (a) employees of ExxonMobil Affiliates who have an appropriate research agreement with ExxonMobil Research and Engineering Company (EMRE), and (b) consultants, contractors, or employees of third parties with whom proper secrecy agreements have been executed with EMRE or such ExxonMobil Affiliates. ExxonMobil Research and Engineering Company

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October, 2004

Figure 1 - Definition Of Knee Point

VK

+10%

VK

Exciting Voltage (Vs)

+50% /eK

/eK

Exciting Voltage (/ e)

This information is considered CONFIDENTIAL and shall not be released to or discussed with any persons except (a) employees of ExxonMobil Affiliates who have an appropriate research agreement with ExxonMobil Research and Engineering Company (EMRE), and (b) consultants, contractors, or employees of third parties with whom proper secrecy agreements have been executed with EMRE or such ExxonMobil Affiliates. ExxonMobil Research and Engineering Company

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Figure 2 - Current Limiting Fuse

Current

Prospective Current

Cut-Off Current (Peak Let-Through)

One Cycle

Total Clearing Time

Pre - Arcing Time

Fault Inception

Time

This information is considered CONFIDENTIAL and shall not be released to or discussed with any persons except (a) employees of ExxonMobil Affiliates who have an appropriate research agreement with ExxonMobil Research and Engineering Company (EMRE), and (b) consultants, contractors, or employees of third parties with whom proper secrecy agreements have been executed with EMRE or such ExxonMobil Affiliates. ExxonMobil Research and Engineering Company

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Figure 3 - Instantaneous Relay Current vs Time Curve With Or Without D.C. Filter

Fault Current

I

Current "Seen" by Relay (RMS)

t

Symmetrical Current

This information is considered CONFIDENTIAL and shall not be released to or discussed with any persons except (a) employees of ExxonMobil Affiliates who have an appropriate research agreement with ExxonMobil Research and Engineering Company (EMRE), and (b) consultants, contractors, or employees of third parties with whom proper secrecy agreements have been executed with EMRE or such ExxonMobil Affiliates. ExxonMobil Research and Engineering Company

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Figure 4 - Instantaneous Relay Current vs. Time Curve Sensitive To Current Offset (D.C.)

Fault Current

I

Current "Seen" by Relay (RMS)

t Asymmetrical Current

This information is considered CONFIDENTIAL and shall not be released to or discussed with any persons except (a) employees of ExxonMobil Affiliates who have an appropriate research agreement with ExxonMobil Research and Engineering Company (EMRE), and (b) consultants, contractors, or employees of third parties with whom proper secrecy agreements have been executed with EMRE or such ExxonMobil Affiliates. ExxonMobil Research and Engineering Company

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October, 2004

Figure 5 - Instantaneous Relay Current Vs. Time Curve With D.C. Component Filtered Out Fault Current

I Current "Seen by Relay (RMS Minus d.c.)

t

d.c. Component Asymmetrical Current

Figure 6 - Instantaneous Relay Overreach Vs. System Angle

(Low Overreach Relay) 12

Overreach %

10 8 6 4 2 0 84°

85°

86°

87°

88°

System Angle This information is considered CONFIDENTIAL and shall not be released to or discussed with any persons except (a) employees of ExxonMobil Affiliates who have an appropriate research agreement with ExxonMobil Research and Engineering Company (EMRE), and (b) consultants, contractors, or employees of third parties with whom proper secrecy agreements have been executed with EMRE or such ExxonMobil Affiliates. ExxonMobil Research and Engineering Company

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Figure 7 - Instantaneous Relay Operating Time Vs. Current

70

Operating Time (Milliseconds)

60

50

40 30

20

Low Setting High Setting

10

0 0

1

2

3

4

5

6

7

8

9

10

Multiples of Setting Current

This information is considered CONFIDENTIAL and shall not be released to or discussed with any persons except (a) employees of ExxonMobil Affiliates who have an appropriate research agreement with ExxonMobil Research and Engineering Company (EMRE), and (b) consultants, contractors, or employees of third parties with whom proper secrecy agreements have been executed with EMRE or such ExxonMobil Affiliates. ExxonMobil Research and Engineering Company

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Figure 8 - Typical Time vs. Current Curves Of Relays With Inverse Time Characteristics 20

10 9 8 7 6 5 4 3

10 9 8 7 6 5

1 .9 .8 .7 .6

4

.5

3

.4

2

.3

Time Dial Settings

Time in Seconds

2

1

.2

Aw .1 .09 .08 .07 .06 .05 .04 .03 .02

.01 .5 .6 .7 .8 .9 1

2

3

4

5

6 7 8 910

20

30

40 50

60

70 90 80 100

Multiples of Relay Tap Setting This information is considered CONFIDENTIAL and shall not be released to or discussed with any persons except (a) employees of ExxonMobil Affiliates who have an appropriate research agreement with ExxonMobil Research and Engineering Company (EMRE), and (b) consultants, contractors, or employees of third parties with whom proper secrecy agreements have been executed with EMRE or such ExxonMobil Affiliates. ExxonMobil Research and Engineering Company

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Figure 9 - Inverse Time Overcurrent Relay Slopes Extremely Inverse

Time

Very Inverse

Inverse

Multiples of Pickup Current

Figure 10 - Definite Time Overcurrent Relay Time vs. Current Curve

Time

Adjustable Pickup Current

Adjustable Time Delay

Current

This information is considered CONFIDENTIAL and shall not be released to or discussed with any persons except (a) employees of ExxonMobil Affiliates who have an appropriate research agreement with ExxonMobil Research and Engineering Company (EMRE), and (b) consultants, contractors, or employees of third parties with whom proper secrecy agreements have been executed with EMRE or such ExxonMobil Affiliates. ExxonMobil Research and Engineering Company

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Figure 11 - Generator Cable Protection with Directional Relay (Not Recommended)

87

67

This information is considered CONFIDENTIAL and shall not be released to or discussed with any persons except (a) employees of ExxonMobil Affiliates who have an appropriate research agreement with ExxonMobil Research and Engineering Company (EMRE), and (b) consultants, contractors, or employees of third parties with whom proper secrecy agreements have been executed with EMRE or such ExxonMobil Affiliates. ExxonMobil Research and Engineering Company

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DESIGN PRACTICES

ELECTRICAL POWER FACILITIES

Section

Page

SYSTEM AND EQUIPMENT

XXX-E

64 of 97

PROTECTIVE RELAYING

October, 2004

Figure 12 - Generator Cable Protection with Differential Relay (Recommended)

87

This information is considered CONFIDENTIAL and shall not be released to or discussed with any persons except (a) employees of ExxonMobil Affiliates who have an appropriate research agreement with ExxonMobil Research and Engineering Company (EMRE), and (b) consultants, contractors, or employees of third parties with whom proper secrecy agreements have been executed with EMRE or such ExxonMobil Affiliates. ExxonMobil Research and Engineering Company

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DESIGN PRACTICES

ELECTRICAL POWER FACILITIES

Section

Page

SYSTEM AND EQUIPMENT

XXX-E

65 of 97

PROTECTIVE RELAYING

October, 2004

Figure 13 - Cable Differential Protection

3

3

87 3 Figure 14 - Transformer Differential Protection

3

3

87T 3

This information is considered CONFIDENTIAL and shall not be released to or discussed with any persons except (a) employees of ExxonMobil Affiliates who have an appropriate research agreement with ExxonMobil Research and Engineering Company (EMRE), and (b) consultants, contractors, or employees of third parties with whom proper secrecy agreements have been executed with EMRE or such ExxonMobil Affiliates. ExxonMobil Research and Engineering Company

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Section

Page

SYSTEM AND EQUIPMENT

XXX-E

66 of 97

DESIGN PRACTICES

PROTECTIVE RELAYING

October, 2004

Figure 15 - Generator Or Motor Differential Protection

(Lower Sketch Of “Self Balancing" Scheme Is Preferred For Motors)

3

3

87 3

3

87 3

Figure 16 - Busbar Differential Protection

3 67 3

3

3

3

3

This information is considered CONFIDENTIAL and shall not be released to or discussed with any persons except (a) employees of ExxonMobil Affiliates who have an appropriate research agreement with ExxonMobil Research and Engineering Company (EMRE), and (b) consultants, contractors, or employees of third parties with whom proper secrecy agreements have been executed with EMRE or such ExxonMobil Affiliates. ExxonMobil Research and Engineering Company

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DESIGN PRACTICES

ELECTRICAL POWER FACILITIES

Section

Page

SYSTEM AND EQUIPMENT

XXX-E

67 of 97

PROTECTIVE RELAYING

October, 2004

Figure 17- Standard Differential Protection

3

3

4 or 6 Conductors 87 3 Figure 18 - Pilot Wire Differential Protection

3

3

2 Conductors (1 Pair) 85

85 1

1

This information is considered CONFIDENTIAL and shall not be released to or discussed with any persons except (a) employees of ExxonMobil Affiliates who have an appropriate research agreement with ExxonMobil Research and Engineering Company (EMRE), and (b) consultants, contractors, or employees of third parties with whom proper secrecy agreements have been executed with EMRE or such ExxonMobil Affiliates. ExxonMobil Research and Engineering Company

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DESIGN PRACTICES

ELECTRICAL POWER FACILITIES

Section

Page

SYSTEM AND EQUIPMENT

XXX-E

68 of 97

PROTECTIVE RELAYING

October, 2004

Relaying Point

Figure 19 - Distance (Impedance) Protection

To 200%

200% of Line 1.5 Seconds

120% of Line 0.5S

80% of Line 0.1S

3 21

A

B

C

Length of Line

This information is considered CONFIDENTIAL and shall not be released to or discussed with any persons except (a) employees of ExxonMobil Affiliates who have an appropriate research agreement with ExxonMobil Research and Engineering Company (EMRE), and (b) consultants, contractors, or employees of third parties with whom proper secrecy agreements have been executed with EMRE or such ExxonMobil Affiliates. ExxonMobil Research and Engineering Company

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DESIGN PRACTICES

ELECTRICAL POWER FACILITIES

Section

Page

SYSTEM AND EQUIPMENT

XXX-E

69 of 97

PROTECTIVE RELAYING

October, 2004

Figure 20 - Time Grading Selectivity

Bus A 5

4 Bus D 3

3

2

2 Bus C

1

M

Bus D

1

M

1

M

1

M

1

M

This information is considered CONFIDENTIAL and shall not be released to or discussed with any persons except (a) employees of ExxonMobil Affiliates who have an appropriate research agreement with ExxonMobil Research and Engineering Company (EMRE), and (b) consultants, contractors, or employees of third parties with whom proper secrecy agreements have been executed with EMRE or such ExxonMobil Affiliates. ExxonMobil Research and Engineering Company

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DESIGN PRACTICES

ELECTRICAL POWER FACILITIES

Section

Page

SYSTEM AND EQUIPMENT

XXX-E

70 of 97

PROTECTIVE RELAYING

October, 2004

Figure 21 - Current Grading

Power Source Bus A

B Load Bus

This information is considered CONFIDENTIAL and shall not be released to or discussed with any persons except (a) employees of ExxonMobil Affiliates who have an appropriate research agreement with ExxonMobil Research and Engineering Company (EMRE), and (b) consultants, contractors, or employees of third parties with whom proper secrecy agreements have been executed with EMRE or such ExxonMobil Affiliates. ExxonMobil Research and Engineering Company

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DESIGN PRACTICES

ELECTRICAL POWER FACILITIES

Section

Page

SYSTEM AND EQUIPMENT

XXX-E

71 of 97

PROTECTIVE RELAYING

October, 2004

el t

l2 t

le ar in g

M

C Pr

e

-A

rc in g

or M

in im

um

To ta l

Amp Squared Seconds

l2 t

Figure 22 - Selectivity Between Fuses

Fuse Rating in Amps

This information is considered CONFIDENTIAL and shall not be released to or discussed with any persons except (a) employees of ExxonMobil Affiliates who have an appropriate research agreement with ExxonMobil Research and Engineering Company (EMRE), and (b) consultants, contractors, or employees of third parties with whom proper secrecy agreements have been executed with EMRE or such ExxonMobil Affiliates. ExxonMobil Research and Engineering Company

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DESIGN PRACTICES

ELECTRICAL POWER FACILITIES

Section

Page

SYSTEM AND EQUIPMENT

XXX-E

72 of 97

PROTECTIVE RELAYING

Figure 24 - Instantaneous Relay Operation At Less Than Half A Cycle

Current

Figure 23 - Instantaneous Relay Set Point

October, 2004

2

Current

>

2

Relay Setting

1

t

1

t

This information is considered CONFIDENTIAL and shall not be released to or discussed with any persons except (a) employees of ExxonMobil Affiliates who have an appropriate research agreement with ExxonMobil Research and Engineering Company (EMRE), and (b) consultants, contractors, or employees of third parties with whom proper secrecy agreements have been executed with EMRE or such ExxonMobil Affiliates. ExxonMobil Research and Engineering Company

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DESIGN PRACTICES

ELECTRICAL POWER FACILITIES

Section

Page

SYSTEM AND EQUIPMENT

XXX-E

73 of 97

PROTECTIVE RELAYING

October, 2004

Figure 25 - Selectivity Between An Instantaneous Relay And A Current Limiting Fuse

I Prospective Fault Current

Relay Setting Peak and Fuse Let – Through Relay Setting (rms) = (100/

2 ) x Peak = 70% Peak

Relay Setting Current Waveform

t

This information is considered CONFIDENTIAL and shall not be released to or discussed with any persons except (a) employees of ExxonMobil Affiliates who have an appropriate research agreement with ExxonMobil Research and Engineering Company (EMRE), and (b) consultants, contractors, or employees of third parties with whom proper secrecy agreements have been executed with EMRE or such ExxonMobil Affiliates. ExxonMobil Research and Engineering Company

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DESIGN PRACTICES

ELECTRICAL POWER FACILITIES

Section

Page

SYSTEM AND EQUIPMENT

XXX-E

74 of 97

PROTECTIVE RELAYING

October, 2004

kA Peak

Figure 26 - Fuse Peak Let-Through Current Curves

B

Peak Let – Through Current

200

A Fu

A 100 50 A 20 A 10 A

se

Fuse

Fuse e Fus Fuse

A

rms Symmetrical

System Short Circuit Current

This information is considered CONFIDENTIAL and shall not be released to or discussed with any persons except (a) employees of ExxonMobil Affiliates who have an appropriate research agreement with ExxonMobil Research and Engineering Company (EMRE), and (b) consultants, contractors, or employees of third parties with whom proper secrecy agreements have been executed with EMRE or such ExxonMobil Affiliates. ExxonMobil Research and Engineering Company

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Section

Page

SYSTEM AND EQUIPMENT

XXX-E

75 of 97

DESIGN PRACTICES

PROTECTIVE RELAYING

October, 2004

Figure 27 - Backup Protection

Relay 3 51V

Gen 1 87

Relay 4

51

Relay 2

51

Relay 1

This information is considered CONFIDENTIAL and shall not be released to or discussed with any persons except (a) employees of ExxonMobil Affiliates who have an appropriate research agreement with ExxonMobil Research and Engineering Company (EMRE), and (b) consultants, contractors, or employees of third parties with whom proper secrecy agreements have been executed with EMRE or such ExxonMobil Affiliates. ExxonMobil Research and Engineering Company

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SYSTEM AND EQUIPMENT

XXX-E

76 of 97

DESIGN PRACTICES

PROTECTIVE RELAYING

October, 2004

Figure 28 - Motor Control Circuits

50/51

49

49

Same as A, B, or C

3

49

3

3

3 50GS 1

(A) LV Contactor and Fuses

(B) LV Contactor and Fuses

(C) LV Contactor and MCB

1

(D) LV Contactor With Ground Relay

**

27 1

27 1 3

86HR 1

HR 86HR

1

49

1

49/50

*

50GS 1

1

49 3

51 3

3

51 3

1

1 50GS

50GS 1 (E) LV Circuit Breaker

*** 1

(F) MV Contactor

1 1

1

(G) MV Circuit Breaker

Notes: * Not required on high resistance grounded circuits. ** May not be required if incorporated in the circuit breaker. *** Differential protection 87 required for motors 1801 kW and above. HR Hand reset. The following details are not normally drawn on single line diagrams but have been shown here to illustrate the protection more fully – Direct acting trip device number, number of elements, and trip signal. – Trip signal from striker pins.

This information is considered CONFIDENTIAL and shall not be released to or discussed with any persons except (a) employees of ExxonMobil Affiliates who have an appropriate research agreement with ExxonMobil Research and Engineering Company (EMRE), and (b) consultants, contractors, or employees of third parties with whom proper secrecy agreements have been executed with EMRE or such ExxonMobil Affiliates. ExxonMobil Research and Engineering Company

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DESIGN PRACTICES

ELECTRICAL POWER FACILITIES

Section

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SYSTEM AND EQUIPMENT

XXX-E

77 of 97

PROTECTIVE RELAYING

October, 2004

Figure 29 - Transformer Protection b 50/51 3

3 50 GS

1

1

< 500 kVA

b

b 50/51 3

3

3

3

50/51 3

50 GS 1

1

50 GS 1

1 Alarm

1

Alarm

63

87 T

63 1

1

3

1 51 G

1

1

51 G 1

3 Note 1

Note 1

> 500 kVA

86

> 500 kVA with Differential

Notes: (1) Low resistance and solidly grounded neutrals require

51G

as shown.

(2) Temperature relays (26) also provided. Refer to text.

This information is considered CONFIDENTIAL and shall not be released to or discussed with any persons except (a) employees of ExxonMobil Affiliates who have an appropriate research agreement with ExxonMobil Research and Engineering Company (EMRE), and (b) consultants, contractors, or employees of third parties with whom proper secrecy agreements have been executed with EMRE or such ExxonMobil Affiliates. ExxonMobil Research and Engineering Company

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DESIGN PRACTICES

ELECTRICAL POWER FACILITIES

Section

Page

SYSTEM AND EQUIPMENT

XXX-E

78 of 97

PROTECTIVE RELAYING

October, 2004

Figure 30 - Partial Differential Protection

Relay B Relay A 51 51

Bus A

Bus B

Fault

This information is considered CONFIDENTIAL and shall not be released to or discussed with any persons except (a) employees of ExxonMobil Affiliates who have an appropriate research agreement with ExxonMobil Research and Engineering Company (EMRE), and (b) consultants, contractors, or employees of third parties with whom proper secrecy agreements have been executed with EMRE or such ExxonMobil Affiliates. ExxonMobil Research and Engineering Company

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DESIGN PRACTICES

ELECTRICAL POWER FACILITIES

Section

Page

SYSTEM AND EQUIPMENT

XXX-E

79 of 97

PROTECTIVE RELAYING

October, 2004

REMARKS

By

Sheet Revision Date

of

Figure 31 - Relay Settings Record

Volts Cyc Volts Cyc

Volts Cyc

Volts Cyc

Calibrate Check Calibrate Check CT or PT Time Inst AmpsTime AmpsTime AmpsTime AmpsTime Ratio Tap Dial or Sec or Sec or Sec or Sec Inst

Range

Mfg. Model No. Time Char

RELAY DESCRIPTION

Voltage

Instruct Time Book No.

SETTINGS

TEST POINTS

FIELD TESTS

Coord Curve Symbol Service Panel or ANSI Feeder Symbol No.

RELAY

Substation

Phase

This information is considered CONFIDENTIAL and shall not be released to or discussed with any persons except (a) employees of ExxonMobil Affiliates who have an appropriate research agreement with ExxonMobil Research and Engineering Company (EMRE), and (b) consultants, contractors, or employees of third parties with whom proper secrecy agreements have been executed with EMRE or such ExxonMobil Affiliates. ExxonMobil Research and Engineering Company

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ELECTRICAL POWER FACILITIES

Section

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SYSTEM AND EQUIPMENT

XXX-E

80 of 97

PROTECTIVE RELAYING

October, 2004

Figure 32 - Relay Coordination Graph Paper 5000 6000 7000 8000 9000 10000

4000

3000

2000

400 500 600 700 800 900 1000

300

5 6 7 89

200

4

40 50 60 70 80 90 100

3

30

2

20

.5 .6 .7.8.91

1000 900 800 700 600 500 300

200

200

100 90 80 70 60 50

100 90 80 70 60 50

40

40

30

30

20

20

10 9 8 7 6 5

10 9 8 7 6 5

4

4

3

3

2

2

1 .9 .8 .7 .6 .5 .4

1 .9 .8 .7 .6 .5 .4

.3

.3

.2

.2

.1 .09 .08 .07 .06 .05

.1 .09 .08 .07 .06 .05

.04

.04

.03

.03

.02

.02

4000

3000

2000

500 600 700 800 900 1000

400

300

200

5 6 7 89

50 60 70 80 90 100

4

40

3

10

2

30

.01 .5 .6 .7 .8.91

20

.01

TIME IN SECONDS

400

300

5000 6000 7000 8000 9000 10000

TIME IN SECONDS

1000 900 800 700 600 500 400

10

CURRENT IN AMPERES

CURRENT IN AMPERES TIME – CURRENT CHARACTERISTIC CURVES For Fuse Links, In BASIS FOR DATA Standards Dated p.f., Starting at 25C with no initial load 1. Tests made at Volts a-c at.. Test points so variations should be 2. Curves are plotted to

No. Date

NOTE: Use Full Size Graph Paper (11"x17")

This information is considered CONFIDENTIAL and shall not be released to or discussed with any persons except (a) employees of ExxonMobil Affiliates who have an appropriate research agreement with ExxonMobil Research and Engineering Company (EMRE), and (b) consultants, contractors, or employees of third parties with whom proper secrecy agreements have been executed with EMRE or such ExxonMobil Affiliates. ExxonMobil Research and Engineering Company

1

PM 302C

235

1

50G 300/5

300/5

50 51

49

1

2

CM 302

PM 301A

1 50 51

27

27R

PM 301B

1

1

50G

50 51

49

PM 302B

235

50G 300/5

49 75/5 2 50 51 1

CM 301C

1250

50G 300/5

1250

300/5

75/5

2400V Motor Control Center No. 2

1200/5

600A Resistor

50 51 3 3750 kVA 13-2/2-4kV 51G 1 300/5

2400/ 12kV

3

49 75/5 2 50 51 1

2400/120V

2

1

400/5

1 Bus 2

50N 51N

271

Substation 23

27R

1

1

271 50N 51N

2 Bus 1

1

2400/120V

3

50 51

27

2400/12kV

50G 300/5 50G 1 1 210 1250

49 75/5 2 50 51 1

75/5

2400V Motor Control Center No. 1

1200/5

51G

49 75/5 2 50 51 1

Feeder No. 1 3750 kVA 13-2/2-4kV

400/5

1

1

2

1 1

51G

Largest 33HP

M

100AF 100A

480V MCC No. 1

1200/5

400/5

50 51 3

1

480/ 120V

1

480V TPC

1

27R

2

1

600AF 225A

50 51

27

100/5

1 Bus 2

50N 51N

271

S/S 23A

1

27R

1 1

271 50N 51N

2 Bus 1 600AF 225A

3

50 51

27

966kVA 13200/480V

100/5 3

3

1200/5

3 966kVA 13200/480V 51G 1 400/5

50 51

Largest 33HP

M

100AF 100A

480V MCC No. 2

3

DESIGN PRACTICES

600A Resistor

300/5

3

Feeder No. 2

50 51 3

ExxonMobil Proprietary CONFIDENTIAL

ELECTRICAL POWER FACILITIES Section Page

SYSTEM AND EQUIPMENT XXX-E 81 of 97

PROTECTIVE RELAYING October, 2004

Figure 33 - Relay Coordination Sample One Line Diagram

Lighting Panel D

Welding Outlets

This information is considered CONFIDENTIAL and shall not be released to or discussed with any persons except (a) employees of ExxonMobil Affiliates who have an appropriate research agreement with ExxonMobil Research and Engineering Company (EMRE), and (b) consultants, contractors, or employees of third parties with whom proper secrecy agreements have been executed with EMRE or such ExxonMobil Affiliates. ExxonMobil Research and Engineering Company

23

50P-2 51P-2

3

"

Bus 2 - Incoming AB Line

51G-2

27-2

27I-2

3

2

2 AB

Inst

"

"

"

"

" "

" "

"

"

"

"

2422PB

RAV11B2A

NGV13B30A

IAV54E1A

1AC51A2A

"

Def TD

Inst.

Inst.

"

"

"

"

"

NGV13B30A

IAV54E1A

IAC51A2A

Inst.

"

"

IAC51B22A Inverse

"

IAC53B101A Very Inverse

"

"

1.5-6A

05.2A

"

"

0.2-5 SEC

-

-

-

-

18-36V

80-120V

-

-

2-8A

"

"

" "

"

"

1.5-6A

GEI-90805

-

"

"

2-8A

"

80-120V

GEH-1768 55-140V

"

GEH-1753 0.5-2A

"

GEH-1788 4-16A 10-40A

"

"

GEH-1753 4-16A 20-80A

"

SR-15-X

GEI-44220

GEI-90805

GEH-1768 55-140V

"

IAC51B22A Inverse GEH-1753

"

SETTINGS

2.5

0.5

"

8

"

"

8

-

-

-

-

93

2.5

0.5

"

8

"

"

8

"

-

2400-120V 93

300/5A

"

"

1200/5A

"

"

400/5A

-

-

"

"

2400-120V

300/5A

"

"

1200/5A

"

"

400/5A

-

1.5

2

1

"

2.5

"

"

"

0

0.39 23.4

"

0.67 40.2

"

"

0.73 43.8

1 60

3 180

d.o.

0

75

5

1

"

16

"

"

16

-

-

78

d.o. 110

1.0 60

0.73 12.5 43.8

2.5

"

40

"

"

40

d.o.

d.o.

30

75

5

1

"

16

"

"

16

2.8 168

1.48 88.8

0.75 45

"

3.4 204

"

"

1.48 88.8

-

max p.u.

R4

R3

"

R2

"

"

R1

-

-

-

-

R5

R4

R3

R2

"

"

R1

R5

Check AmpsTime or Sec Volts Cyc

AmpsTime or Sec Volts Cyc

FIELD TESTS Calibrate

Coord Curve Symbol

2.8 168

1.48 88.8

0.75 45

"

3.4 204

"

"

1.48 88.8

-

-

max. p.u.

max. d.o. 110 p.u.

1.0 60

12.5 0.73 43.8

0.39 2.5 23.4

"

100 100

-

-

2

"

33

"

"

51

-

1 sec 2

-

30

"

"

0.67 40 40.2

"

"

0.73 40 43.8

100 100

-

-

2

"

33

"

"

51

3 sec

-

-

1.5

2

1

"

2.5

"

"

2

Volts Cyc Volts Cyc

TEST POINTS

Calibrate Check CT or PT Time Inst AmpsTime Amps Time Ratio Tap Dial or Sec or Sec

d.o. = drop-out p.u. = pick-up

REMARKS

Sheet 1 of 2 Revision 0 Date 1/5/71 By CWL

PROTECTIVE RELAYING

"

"

N

"

3750 KVA Transformer Neutral - Bus 2

3 "

G

"

"

"

"

" "

C

Instruct Time Book No.

IAC53B101A Very GEH-1788 4-16A 10-40A Inverse

"

"

GE IAC51B104A Inverse

"

C

B

A

-

Aga

"

AB C -

"

AB

"

"

"

"

"

"

"

3750 KVA Transformer A Secondary - Bus 2

"

"

3750 KVA Transformer Primary - Bus 2

"

"

Bus 1

"

Time Char

Range

GE IAC51B104A Inverse GEH-1753 4-16A 20-80A

50N-2 51N-2

3

3

50-2 51-2

"

97-1

2

3

96-1

2

"

27R-1

2

3

27I-1

2

AB

27-1

2

N

51G-1

1

G

Bus 1 Incoming Line

"

1

C

3750 KVA Transformer Neutral - Bus 1

"

"

50N-1 51N-1

1

C

B

A

Phase

3750 KVA Transformer A Secondary - Bus 1

"

"

3750 KVA Transformer Primary - Bus 1

Mfg. Model No.

RELAY DESCRIPTION

Voltage 13800-2400

DESIGN PRACTICES

1

"

50-1 51-1

"

1

1

50P-1 51P-1

1

RELAY Panel or ANSI Feeder Service Symbol No.

Substation

ExxonMobil Proprietary CONFIDENTIAL

ELECTRICAL POWER FACILITIES Section Page

SYSTEM AND EQUIPMENT XXX-E 82 of 97

October, 2004

Figure 34 - Typical Relay Settings Record (13.8/2.4 KV) (Part 1 Of 2)

This information is considered CONFIDENTIAL and shall not be released to or discussed with any persons except (a) employees of ExxonMobil Affiliates who have an appropriate research agreement with ExxonMobil Research and Engineering Company (EMRE), and (b) consultants, contractors, or employees of third parties with whom proper secrecy agreements have been executed with EMRE or such ExxonMobil Affiliates. ExxonMobil Research and Engineering Company

G AC

"

PM302-C

"

"

CM-302

"

97-2

49

50 51

50G

49

50 51

50G

MCC1

"

"

"

"

"

"

"

"

50 51

G AC

"

"

PM-301C

"

49

50 51

50G

49

50 51

50G

"

"

"

"

"

AC

PM-302B

"

"

49

50 51

50G

"

"

G "

" IC2820A102

-

GEH-3071

-

GEI-44233 4-8A

Inst.

-

-

GEH-3071

-

GEH-3071

-

GEI-44233 4-8A

GEH-3071

-

GEI-44233 4-8A

GEH-3071

-

GEI-44233 4-8A

4-12A 20-80A

-

-

4-12A 20-80A

-

-

4-12A 20-80A

-

-

4-12A GEI-44233 4-8A 20-80A

Inverse GES-5000A 85-115%

Inst.

-

4-12A 20-80A

Inverse GES-5000A 85-115%

Inst.

Long IAC66K19A Inverse

CR124A2

IC2820A102

-

4-12A 20-80A

Inverse GES-5000A 85-115%

Inst.

Long IAC66K19A Inverse

CR124A2

IIC2820A102

GEH-3071

GEI-44233 4-8A

Inverse GES-5000A 85-115%

Inst.

Long Inverse

Long IAC66K19A Inverse

CR124A2

IC2820A102

"

-

18-36V

Inverse GES-5000A 85-115% -

Inst.

Long Inverse

Long TAC66K19A Inverse

CR124A2

IC2820A102

TAC66K19A

CR124A2

IC2820A102

IAC66K19A

"

SR-15-X

0.2-5 SEC

-

Inverse GES-5000A 85-115% -

"

Def TD

GEI44220

300/5A

"

75/5A

300/5A

"

400/5A

300/5A

"

400/5A

300/5A

"

400/5A

300/5A

"

75/5A

300/5

"

75/5A

-

-

2400-120V

4.5

91%

4.5

97%

4.5

2

-

1.5

-

Factory Set

2

-

Factory Set

5.3

38 sec

8.5

8.0

40 sec

-

8.5

-

-

8.8 -

-

38 sec

9

5.1

6.7 402

38 sec

9

5.3

120 sec

12 720

125 sec

12 720

125 sec

12 720

125 sec

17 1020 See Remarks

22.5

8.5

9

5.1

See Remarks

4.8 22.5 288

8.5

4.8 288

38 sec

See Remarks

22.5

8.5

9

5.1

See Remarks

4.8 8.5 22.5 288 -

38 sec

115 sec 17 1020

See Remarks

9

5.0

-

-

-

R8

R7

R6

R8

R7

R6

R8

R7

R6

-

-

-

-

-

-

120 sec 17 1020

-

-

-

-

-

max. p.u.

See Remarks

6.7 8.2 22.5 402 -

-

8.5 1.5 -

-

-

1 60

9

-

3 d.o. 180 d.o.

78

d.o.

30

Volts Cyc Volts Cyc

6.7 8.8 22.5 402 -

8.5 -

Factory Set

1.5

-

Factory Set 97%

4.5

2

Factory Set 97%

4.5

-

1 sec -

-

3 sec

-

30

-

Factory Set 94%

4.5

91%

-

-

-

Check AmpsTime or Sec Volts Cyc

AmpsTime or Sec Volts Cyc

FIELD TESTS Calibrate

"

"

Ditto PM302-C

"

Ditto PM302-C

Ditto PM301-A

"

Ditto PM302-C

Ditto PM301-A

"

Ditto PM302-C

Heater No.CR123C3.79A E1-2 Fuse 4R

"

Ditto PM302-C

Heater No. CR123C3.79A E1-2 Fuse 4R

Check pu. Should pu on 15-amp in CT pri

Set High d.o. 50 Unit Normal d.o. Unit Not Used

Heater No. CR123C4.19A E 1-2 Fuse 4R

REMARKS

PROTECTIVE RELAYING

B

"

G

" "

"

"

"

"

"

"

"

B

B

AC

PM-301B

MCC2

G

50G

"

"

AC

PM-301A

49 B

"

G

"

"

"

"

"

"

B

B

CR124A2

2422PB

2422PB

Inst.

TEST POINTS

Sheet 2 of 2 Revision 0 Date 1/5/71 By CWL

DESIGN PRACTICES

"

"

Aga

AC GE

-

-

2

"

96-2

2

RAV11B2A

SETTINGS

Relay Data and Coordination Guide Part 1 - Documentation ESSO Engineering Calibrate Check CT or PT Time Inst AmpsTime AmpsTime Ratio Tap Dial Inst or Sec or Sec

Range Instruct Time Book No.

RELAY DESCRIPTION

Voltage 13800-2400

Mfg. Model No. Time Char

AB GE C

27R-2

Bus 2

Phase

2

RELAY Panel or Feeder ANSI Service Symbol No.

23 Coord Curve Symbol

Substation

ExxonMobil Proprietary CONFIDENTIAL

ELECTRICAL POWER FACILITIES Section Page

SYSTEM AND EQUIPMENT XXX-E 83 of 97

October, 2004

Figure 34 (Cont) Typical Relay Settings Record (13.8/2.4 Kv) (Part 2 Of 2)

This information is considered CONFIDENTIAL and shall not be released to or discussed with any persons except (a) employees of ExxonMobil Affiliates who have an appropriate research agreement with ExxonMobil Research and Engineering Company (EMRE), and (b) consultants, contractors, or employees of third parties with whom proper secrecy agreements have been executed with EMRE or such ExxonMobil Affiliates. ExxonMobil Research and Engineering Company

C A

"

"

"

750 KVA Transformer Primary - Bus 2

"

750 KVA Transformer Secondary - Bus 2

"

"

50-1 51-1

"

50N-1 51N-1

51G-1

27-1

271-1

27R-1

96-1

97-1

50P-2 51P-2

"

"

50-2 51-2

"

50N-2 51N-2

51G-2

27-2

271-2

1

1

1

1

2

2

2

2

2

3

3

3

3

3

3

3

3

3 AB

AB

Time Char

"

"

"

2422PB

RAV11B2A

NGV13B30A

IAV54EIA

IAC51A2A

IAC51B22A

"

"

Def TD

Inst.

Inst.

"

"

Inverse

"

Very Inverse

"

"

"

"

"

"

"

"

"

" "

"

NGV13B30A

IAV54E1A

IAC51A2A

IAC51B22A

"

Inst.

"

"

Inverse

"

Very IAC53B101A Inverse

"

"

GE IAC51B104A Inverse

"

Aga

"

"

"

"

"

"

GE 1AC53B101A

"

"

Time

Inst

"

" "

"

"

1.5-6A

-

0.5-2A 2-8A

"

"

-

-

18-36V

80-120V

0.2-5 sec

-

-

"

"

"

"

4-16A 10-40A

"

"

GEI-90805

GEH-1768

"

-

-

-

80-120V

55-140V

1.5-6A

GEH-1753 0.5-2A 2-8A

"

GEH-1788

"

"

GEH-1753 4-16A 20-80A

"

SR-15-X

GEI-44220

GEI-90805

GEH-1768 55-140V -

"

GEH-1753

"

GEH-1788 4-16A 10-40A

"

"

GEH-1753 4-16A 20-80A

Instruct Book No.

Range

"

480-120V

400/5A

"

"

1200/5A

"

"

100/5A

-

-

"

"

480-120V

400/5A

"

"

1200/5

"

"

100/5A

CT or PT Ratio

SETTING

"

" "

"

1.75 41

-

1 sec

"

" "

"

1.75 41

-

30

100

-

-

2

"

3 sec

-

-

1.5

4

1.5

"

-

93

5

1.2

"

-

1.5

4

1.5

"

100

-

-

2

"

10 1.75 35

"

"

8

-

-

-

-

93

5

1.2

"

10 1.75 35

"

"

8

1.0 60

1.4 84

0.55 33

"

0.43 25.8

"

"

0.62 37.2

d.o.

1.0 60

1.4 84

0.55 33

"

0.43 25.8

"

"

0.62 37.2

1 60

100 d.o.

0

25

6

"

50

"

"

40

d.o.

3 d.o. 180

30

100 d.o.

0

25

6

"

50

"

"

40

2.8 168

2.9 174

1.2 72

"

2.25 135

"

"

1.25 75

-

-

p.u.

110 max p.u.

75

10

2.4

"

20

"

"

16

-

-

78

-

R5

R4

R3

"

R2

"

"

R1

-

-

-

-

110 max. p.u.

R4

R3

"

R2

"

"

R1

R5

2.9 174

1.2 72

"

2.25 135

"

"

1.25 75

2.8 168

75

10

2.4

"

20

"

"

16

Check Amps Time or Sec Volts Cyc

FIELD TESTS

Calibrate Check Calibrate Time Amps Time Amps Time Amps Time Tap Inst Dial or Sec or Sec or Sec Volts Cyc Volts Cyc Volts Cyc

SETTING

Relay Data and Coordination Guide Part 1 – Documentation ESSO Engineering

d.o. = drop-out p.u. = pick-up

REMARKS

Sheet 1 of 2 Revision 0 Date 12/18/70 By CWL

PROTECTIVE RELAYING

"

N

Bus 2 - Incoming Line

G

C

B

A

-

-

AB C

750 KVA Transformer Neutral - Bus 2

"

"

Bus 1

AB

AB

"

N

Bus 1 Incoming Line

G

750 KVA Transformer Neutral -Bus 1

Model No.

GE IAC51B104A Inverse

Mfg.

RELAY DESCRIPTION

Voltage 13800 - 480

DESIGN PRACTICES

C

A

C

"

750 KVA Transformer Secondary - Bus 1

"

B

1

"

A

750 KVA Transformer Primary - Bus 1

"

50P-1 51P-1

1

1

Service

RELAY

Panel or ANSI Feeder Symbol No.

Phase

23 A

Coord Curve Symbol

Substation

ExxonMobil Proprietary CONFIDENTIAL

ELECTRICAL POWER FACILITIES Section Page

SYSTEM AND EQUIPMENT XXX-E 84 of 97

October, 2004

Figure 35 - Typical Relay Settings Record (13.8 Kv/480 V)

(Part 1 Of 2)

This information is considered CONFIDENTIAL and shall not be released to or discussed with any persons except (a) employees of ExxonMobil Affiliates who have an appropriate research agreement with ExxonMobil Research and Engineering Company (EMRE), and (b) consultants, contractors, or employees of third parties with whom proper secrecy agreements have been executed with EMRE or such ExxonMobil Affiliates. ExxonMobil Research and Engineering Company

27R-2

96-2

97-2

52

52

52

52

3

3

3

4&5

TPC

TPC

MCC 1&2

Panel or ANSI Feeder Symbol No.

"

"

BUS 2

Service

23A

Mfg.

Model No.

Voltage

-

"

Aga "

2422PB

13800 - 480

"

Def TD

Inst.

Time Char

Motor Control Center ABC Size 3 Starters

"

FA-100

FA-70

"

KA-125

Turnaround Center ABC Lighting Panel D "

"

Thermal Mag

-

-

-

-

-

-

CT or PT Ratio

-

-

-

-

5-10X

-

-

-

-

-

-

18-36V 480-120V

Inst

SETTING

" -

-

-

-

d.c.

d.c.

30

Factory Set

-

-

1 Sec

30 -

3 Sec

Factory Lo Set (5X)

100% 4x

-

-

-

-

-

-

-

1 60

3 180

d.c.

-

-

-

-

-

-

78

-

-

-

-

-

-

p.u.

Check Amps Time or Sec Volts Cyc

FIELD TESTS

Calibrate Check Calibrate Amps Time Amps Time Amps Time Time Tap Inst or Sec or Sec or Sec Dial Volts Cyc Volts Cyc Volts Cyc

SETTING

Relay Data and Coordination Guide Part 1 - Documentation ESSO Engineering

Coord Curve Symbol R9

R8

R7

R6

-

-

-

300 Amp Coil

REMARKS

Sheet 2 of 2 Revision 0 Date 12/18/70 By CWL

DESIGN PRACTICES

Turnaround Center Sq ABC Welding Outlets D

"

0.2-5 Sec

-

Time

Range

80-160% GET-1113 40-10x

"

SR-15-X

GEI-44220

Instruct Book No.

RELAY DESCRIPTION

ABC GE RAV11B2A

Phase

feeders 1 & 2 to EC-1 Series 1-B Int ABC GE Turnaround Center Trip Device 2-C Min

RELAY

Substation

ExxonMobil Proprietary CONFIDENTIAL

ELECTRICAL POWER FACILITIES Section Page

SYSTEM AND EQUIPMENT XXX-E 85 of 97

PROTECTIVE RELAYING October, 2004

Figure 35 (Cont) Typical Relay Settings Record (13.8 Kv/480 V) (Part 2 Of 2)

This information is considered CONFIDENTIAL and shall not be released to or discussed with any persons except (a) employees of ExxonMobil Affiliates who have an appropriate research agreement with ExxonMobil Research and Engineering Company (EMRE), and (b) consultants, contractors, or employees of third parties with whom proper secrecy agreements have been executed with EMRE or such ExxonMobil Affiliates. ExxonMobil Research and Engineering Company

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Section

Page

SYSTEM AND EQUIPMENT

XXX-E

86 of 97

DESIGN PRACTICES

PROTECTIVE RELAYING

October, 2004

200

4000

3000

2000

300 200

R5 (27)

100 90 80 70 60 50

R1 (51P)

R7 (50)

30

100 90 80 70 60 50 40 30

20

20

10 9 8 7 6 5

10 9 8 7 6 5

R7 (51)

Transformer Damage Limit

4

4

3

3

2

2

1 .9 .8 .7 .6 .5 .4

1 .9 .8 .7 .6 .5 .4

116% D-Y

TIME IN SECONDS

40

1000 900 800 700 600 500 400

R2 (51)

300

.3

.3

Fuse R1 (50P)

0%

.1 .09 .08 .07 .06 .05

.2

65% 60% 50% 40% 25%

77.5%

.2

.1 .09 .08 .07 .06 .05

% Volts

.04

.03

.03 1 0 – 0 Min 11051A

.02

4000

3000

2000

500 600 700 800 900 1000

400

300

.01 200

5 6 7 89

50 60 70 80 90 100

4

40

3

30

2

10

.5 .6 .7 .8.91

Reaccel 2310A

.01

20 1

1

FL-FA 1218A

.02

130 Max 13777A

.04

5000 6000 7000 8000 9000 10000

TIME IN SECONDS

500 600 700 800 900 1000

R2 (50)

R6 (49)

400

400

5 6 7 89

300

4

200

3

40 50 60 70 80 90 100

2

30

.5 .6 .7.8.91

20

1000 900 800 700 600 500

10

CURRENT IN AMPERES

5000 6000 7000 8000 9000 10000

Figure 36 - Typical 2400v Phase Relaying Curves

CURRENT IN AMPERES TIME – CURRENT CHARACTERISTIC CURVES For Fuse Links, In BASIS FOR DATA Standards Dated p.f., Starting at 25C with no initial load 1. Tests made at Volts a-c at.. Test points so variations should be 2. Curves are plotted to

No. Date

NOTE: Use Full Size Graph Paper (11"x17")

This information is considered CONFIDENTIAL and shall not be released to or discussed with any persons except (a) employees of ExxonMobil Affiliates who have an appropriate research agreement with ExxonMobil Research and Engineering Company (EMRE), and (b) consultants, contractors, or employees of third parties with whom proper secrecy agreements have been executed with EMRE or such ExxonMobil Affiliates. ExxonMobil Research and Engineering Company

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Section

Page

SYSTEM AND EQUIPMENT

XXX-E

87 of 97

DESIGN PRACTICES

PROTECTIVE RELAYING

October, 2004

Figure 37- Typical 2400v Ground Relaying Curves 5000 6000 7000 8000 9000 10000

4000

3000

2000

500 600 700 800 900 1000

400

5 6 7 89

300

4

200

3

40 50 60 70 80 90 100

2

30

.5 .6 .7 .8.91

20

1000 900 800 700 600 500

10

CURRENT IN AMPERES 1000 900 800 700 600 500

400

400

300

300

200

200

100 90 80 70 60 50

100 90 80 70 60 50

40

40

30

30 20

20

4

4

R3 (51N)

3

3

2

2

1 .9 .8 .7 .6 .5 .4

1 .9 .8 .7 .6 .5 .4

.3

.3

R3 (50N)

.2

TIME IN SECONDS

10 9 8 7 6 5

10 9 8 7 6 5

.2

.1 .09 .08 .07 .06 .05

.1 .09 .08 .07 .06 .05 .04

.04

R8 (50G)

.03

4000

3000

2000

500 600 700 800 900 1000

.01 400

5 6 7 89

300

4

40

3

30

2

10

.5 .6 .7 .8.91

20

.01

.02

200

.02

50 60 70 80 90 100

10G Max 600A

.03

5000 6000 7000 8000 9000 10000

TIME IN SECONDS

R4 (51G)

CURRENT IN AMPERES TIME – CURRENT CHARACTERISTIC CURVES For Fuse Links, In BASIS FOR DATA Standards Dated p.f., Starting at 25C with no initial load 1. Tests made at Volts a-c at.. Test points so variations should be 2. Curves are plotted to

No. Date

NOTE: Use Full Size Graph Paper (11"x17")

This information is considered CONFIDENTIAL and shall not be released to or discussed with any persons except (a) employees of ExxonMobil Affiliates who have an appropriate research agreement with ExxonMobil Research and Engineering Company (EMRE), and (b) consultants, contractors, or employees of third parties with whom proper secrecy agreements have been executed with EMRE or such ExxonMobil Affiliates. ExxonMobil Research and Engineering Company

ExxonMobil Proprietary CONFIDENTIAL

DESIGN PRACTICES

ELECTRICAL POWER FACILITIES

Section

Page

SYSTEM AND EQUIPMENT

XXX-E

88 of 97

PROTECTIVE RELAYING

October, 2004

Figure 38 - Typical 2400v Motor Relaying Curves

270 FLA

5000 6000 7000 8000 9000 10000

4000

3000

2000

R6 (49)

300

Motor Running Curve

200

200

Motor Heating

100 90 80 70 60 50

100 90 80 70 60 50

40

40

30

30

20

TIME IN SECONDS

1000 900 800 700 600 500 400

20

R7 (50)

10 9 8 7 6 5

Motor Withstand Locked Rotor (Cold) Motor Withstand Locked Rotor (Warm)

4

10 9 8 7 6 5 4 3

3 2

2

R7 (51)

1 .9 .8 .7 .6 .5 .4

Type EJ-2 Fuse 24R Min. Total Clearing Time

.3 .2

Motor Starting Curve

.1 .09 .08 .07 .06 .05

Type EJ-2 Fuse 24R Max. Total Clearing Time

TIME IN SECONDS

300

400 500 600 700 800 900 1000

5 6 7 89

300

4

200

3

40 50 60 70 80 90 100

2

30

.5 .6 .7.8.91

20

1000 900 800 700 600 500 400

10

CURRENT IN AMPERES

1 .9 .8 .7 .6 .5 .4 .3 .2

.1 .09 .08 .07 .06 .05

.04

.04

.03

.03 .02

.02

1620A Locked Rotor Current 5000 6000 7000 8000 9000 10000

4000

3000

2000

500 600 700 800 900 1000

400

300

200

5 6 7 89

50 60 70 80 90 100

4

40

3

10

2

30

.01 .5 .6 .7 .8.91

20

.01

CURRENT IN AMPERES TIME – CURRENT CHARACTERISTIC CURVES For Fuse Links, In Dated BASIS FOR DATA Standards p.f., Starting at 25C with no initial load 1. Tests made at Volts a-c at.. Test points so variations should be 2. Curves are plotted to

No. Date

NOTE: Use Full Size Graph Paper (11"x17")

This information is considered CONFIDENTIAL and shall not be released to or discussed with any persons except (a) employees of ExxonMobil Affiliates who have an appropriate research agreement with ExxonMobil Research and Engineering Company (EMRE), and (b) consultants, contractors, or employees of third parties with whom proper secrecy agreements have been executed with EMRE or such ExxonMobil Affiliates. ExxonMobil Research and Engineering Company

ExxonMobil Proprietary CONFIDENTIAL

DESIGN PRACTICES

ELECTRICAL POWER FACILITIES

Section

Page

SYSTEM AND EQUIPMENT

XXX-E

89 of 97

PROTECTIVE RELAYING

October, 2004

Figure 39 - Typical 480v Phase Relaying Curves

R2 (51)

1000 900 800 700 600 500 400

400

R5 (27)

300

300 200

200

R6

R1 (51P)

100 90 80 70 60 50

100 90 80 70 60 50

R2 (50)

40

40 30

30

R9

20

10 9 8 7 6 5

10 9 8 7 6 5 4

4

Transformer Damage Limit

3

3

2

2

1 .9 .8 .7 .6 .5 .4

1 .9 .8 .7 .6 .5 .4

116% D-Y

.2

R1 (50P)

.1 .09 .08 .07 .06 .05

0%

Max 15254A

.03

130

.02

4000

3000

2000

500 600 700 800 900 1000

400

.01

300

5 6 7 89

.04

200

4

50 60 70 80 90 100

3

40

2

30

.5 .6 .7 .8.91

10

.01

20

1FL-FA 1164A

.02

1 Reaccel 2310A

.03

10-G 2999A (ARcing) 1 0-0 Min 1298A

% Volts

.04

5000 6000 7000 8000 9000 10000

.1 .09 .08 .07 .06 .05

65% 60% 50% 40% 25%

.3

.2

77.5%

.3

TIME IN SECONDS

20

TIME IN SECONDS

5000 6000 7000 8000 9000 10000

4000

3000

2000

400 500 600 700 800 900 1000

5 6 7 89

300

4

200

3

40 50 60 70 80 90 100

2

30

.5 .6 .7.8.91

20

1000 900 800 700 600 500

10

CURRENT IN AMPERES

CURRENT IN AMPERES TIME – CURRENT CHARACTERISTIC CURVES For Fuse Links, In BASIS FOR DATA Standards Dated p.f., Starting at 25C with no initial load 1. Tests made at Volts a-c at.. Test points so variations should be 2. Curves are plotted to

No. Date

NOTE: Use Full Size Graph Paper (11"x17")

This information is considered CONFIDENTIAL and shall not be released to or discussed with any persons except (a) employees of ExxonMobil Affiliates who have an appropriate research agreement with ExxonMobil Research and Engineering Company (EMRE), and (b) consultants, contractors, or employees of third parties with whom proper secrecy agreements have been executed with EMRE or such ExxonMobil Affiliates. ExxonMobil Research and Engineering Company

ExxonMobil Proprietary CONFIDENTIAL

DESIGN PRACTICES

ELECTRICAL POWER FACILITIES

Section

Page

SYSTEM AND EQUIPMENT

XXX-E

90 of 97

PROTECTIVE RELAYING

October, 2004

Figure 40 - Typical 480v Ground Relaying Curves 5000 6000 7000 8000 9000 10000

4000

3000

2000

400 500 600 700 800 900 1000

5 6 7 89

300

4

200

3

40 50 60 70 80 90 100

2

30

.5 .6 .7.8.91

20

1000 900 800 700 600 500 400

10

CURRENT IN AMPERES 1000 900 800 700 600 500 400 300

300

200

200

R6 100 90 80 70 60 50

100 90 80 70 60 50

40

40

20

R9

10 9 8 7 6 5

10 9 8 7 6 5

4

4

3

3

2

2

R4 (51G)

1 .9 .8 .7 .6 .5 .4

1 .9 .8 .7 .6 .5 .4 .3

.3

R3 (50N)

.2

.2

.1 .09 .08 .07 .06 .05

.04

.04

.03

.03 .02

4000

3000

2000

500 600 700 800 900 1000

400

.01 300

5 6 7 89

200

4

50 60 70 80 90 100

3

40

2

10

.5 .6 .7 .8.91

20

.01

30

1

0-G 2999A (Arcing)

.02

1 0-G Max 15396A

.1 .09 .08 .07 .06 .05

5000 6000 7000 8000 9000 10000

TIME IN SECONDS

20

30

R3 (51N)

TIME IN SECONDS

30

CURRENT IN AMPERES TIME – CURRENT CHARACTERISTIC CURVES For Fuse Links, In Dated BASIS FOR DATA Standards p.f., Starting at 25C with no initial load 1. Tests made at Volts a-c at.. Test points so variations should be 2. Curves are plotted to

No. Date

NOTE: Use Full Size Graph Paper (11"x17")

This information is considered CONFIDENTIAL and shall not be released to or discussed with any persons except (a) employees of ExxonMobil Affiliates who have an appropriate research agreement with ExxonMobil Research and Engineering Company (EMRE), and (b) consultants, contractors, or employees of third parties with whom proper secrecy agreements have been executed with EMRE or such ExxonMobil Affiliates. ExxonMobil Research and Engineering Company

ExxonMobil Proprietary CONFIDENTIAL

DESIGN PRACTICES

ELECTRICAL POWER FACILITIES

Section

Page

SYSTEM AND EQUIPMENT

XXX-E

91 of 97

PROTECTIVE RELAYING

October, 2004

Figure 41 - Typical 480v Turnaround Power Center Relaying Curves 5000 6000 7000 8000 9000 10000

4000

3000

2000

500 600 700 800 900 1000

400

400

1000 900 800 700 600 500 400

300

300

200

200

100 90 80 70 60 50

100 90 80 70 60 50

40

40

30

30

20

20

R7

10 9 8 7 6 5

10 9 8 7 6 5

R8

4

4

3

3

2

2

R6

.2

.2

.1 .09 .08 .07 .06 .05

.1 .09 .08 .07 .06 .05

.04

.04

.03

.03

.02

.02

1

5000 6000 7000 8000 9000 10000

4000

3000

2000

500 600 700 800 900 1000

400

.01 300

200

5 6 7 89

50 60 70 80 90 100

4

40

3

30

10-G 2

20

.5 .6 .7 .8.91

10

1

.01

30 Max 15254A

.3

2999A (Arcing)

.3

FL

1 .9 .8 .7 .6 .5 .4

120A

1 .9 .8 .7 .6 .5 .4

TIME IN SECONDS

1000 900 800 700 600 500

TIME IN SECONDS

300

5 6 7 89

200

4

40 50 60 70 80 90 100

3

30

2

20

.5 .6 .7.8.91

10

CURRENT IN AMPERES

CURRENT IN AMPERES TIME – CURRENT CHARACTERISTIC CURVES For Fuse Links, In BASIS FOR DATA Standards Dated p.f., Starting at 25C with no initial load 1. Tests made at Volts a-c at.. Test points so variations should be 2. Curves are plotted to

No. Date

NOTE: Use Full Size Graph Paper (11"x17")

This information is considered CONFIDENTIAL and shall not be released to or discussed with any persons except (a) employees of ExxonMobil Affiliates who have an appropriate research agreement with ExxonMobil Research and Engineering Company (EMRE), and (b) consultants, contractors, or employees of third parties with whom proper secrecy agreements have been executed with EMRE or such ExxonMobil Affiliates. ExxonMobil Research and Engineering Company

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October, 2004

Figure 42 - Stabilizing Resistor

50N

Stabilizing Resistor

This information is considered CONFIDENTIAL and shall not be released to or discussed with any persons except (a) employees of ExxonMobil Affiliates who have an appropriate research agreement with ExxonMobil Research and Engineering Company (EMRE), and (b) consultants, contractors, or employees of third parties with whom proper secrecy agreements have been executed with EMRE or such ExxonMobil Affiliates. ExxonMobil Research and Engineering Company

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October, 2004

Figure 43 - Typical Fuse I2t Characteristics 30,000,000

10,000,000 This graph shows the ampere 2 seconds (I2t) through under short-circuit conditions corresponding to maximum arc energy iwthin the fuses at rated voltage. It may be used for the purpose of determining fault energy limitation and discrimination.

1,000,000

Discrimination is achieved when the total I 2t of the minor fuse does not exceed the pre-arcing I2t of the major fuse.

TOTAL OPERATING I 2t

AMPERES 2 SECONDS

PRE-ARCING I 2t

100,000

10,000

1,000

1,200

800

400 500

300

200

100

60

30

10

100

FUSE RATING - AMPERES

This information is considered CONFIDENTIAL and shall not be released to or discussed with any persons except (a) employees of ExxonMobil Affiliates who have an appropriate research agreement with ExxonMobil Research and Engineering Company (EMRE), and (b) consultants, contractors, or employees of third parties with whom proper secrecy agreements have been executed with EMRE or such ExxonMobil Affiliates. ExxonMobil Research and Engineering Company

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PROTECTIVE RELAYING

October, 2004

Values are Per Unit Current of Three-Phase Fault on the Secondary with Transformer Ratio of 1:1

i.e. Approx. 16% 1 - 0.8666' = 0.1333 0.1333 0.8666 x 100 = 15.38

.58

0

Therefore the Current in One Primary Phase is 16% Greater Than the Fault Current in thr Secondary

.58

In Example (B) the Secondary Current is really 0.866'

1.0

(C) Phase to Ground Fault .58

1.0

.50

.50

0

.50

.50

1.0

.87

.87

1.0 .58 1.0

1.0

1.0

Transformer Primary

.58

.58

1.0

1.0

Transformer Secondary

(A) Three Phase Fault

(B) Phase to Phase Fault

Figure 44 - Relative Magnitudes Of Fault Currents

This information is considered CONFIDENTIAL and shall not be released to or discussed with any persons except (a) employees of ExxonMobil Affiliates who have an appropriate research agreement with ExxonMobil Research and Engineering Company (EMRE), and (b) consultants, contractors, or employees of third parties with whom proper secrecy agreements have been executed with EMRE or such ExxonMobil Affiliates. ExxonMobil Research and Engineering Company

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October, 2004

Figure 45 - Typical X/R Values (A) X/R Range for Small Generators and Sychronous Motors (Solid Rotor and Salient Pole) 70 High

Typical X/Rac

60 50

Medium

40 Low

30 20 10 0 1000

2500

5000

10000 15000 25000 20000

Nameplate KVA

(B) X/R Range for Power Transformers 60

High Medium

Typical X/Rac

50 40

Low

30 20 10 0

(C) X/R Range for Three-Phase Induction Motors

50

40

Typical X/Rac

1

High

Medium

2

10 50 1000 0 0 3-Phase, FOA-Power transformer MVA (Standard Impedance Limits) (For OA and FA Ratings Apply the Proper Factor) Before Using Curve 5

10

50

Low

30

20

10

0 50

100

250

500

1000

2500

5000

10,000

Nameplate H P

This information is considered CONFIDENTIAL and shall not be released to or discussed with any persons except (a) employees of ExxonMobil Affiliates who have an appropriate research agreement with ExxonMobil Research and Engineering Company (EMRE), and (b) consultants, contractors, or employees of third parties with whom proper secrecy agreements have been executed with EMRE or such ExxonMobil Affiliates. ExxonMobil Research and Engineering Company

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October, 2004

Figure 46 - Logic Diagram Using Standard Symbols (Partial) SELogic Trip Settings TRCOMM

ECOMM Setting ECOMM=POTT ECOMM=DCUB1 ECOMM=DCUM2 ECOMM=DCB Communications Assisted Trip Logic

Relay Word Bits PTRX Z3RB UBB DSTRT BTX ECTT SELogic Trip Settings DTT

Echo Conversion to Trip

Direct Transfer Trip

TRSOTF Switch-Onto-Fault Trip Logic

“Other Trips” Trip Logic

Communications-Assisted Trip

Relay Word Bits SOTFE SELogic Trip Setting TR

OR-1

Relay Word Bits

Minimum Trip Rising Edge Duration Timer Detect

TRIP OR-2 TDURD

SELogic Setting ULTR Trip Seal-in and Unlatch Logic

Unlatch Trip

Serial Port Command TAR R TARGET RESET Pushbutton

TRGTR

This information is considered CONFIDENTIAL and shall not be released to or discussed with any persons except (a) employees of ExxonMobil Affiliates who have an appropriate research agreement with ExxonMobil Research and Engineering Company (EMRE), and (b) consultants, contractors, or employees of third parties with whom proper secrecy agreements have been executed with EMRE or such ExxonMobil Affiliates. ExxonMobil Research and Engineering Company

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PROTECTIVE RELAYING

October, 2004

Figure 47 - Spot Network Relaying (Partial)

Upstream Relaying 50 51

50 51

50GS

50GS

To Paralleled Substations 51G

87TN

87T

Use 87T for 10 MVA

Resistor

86T

67

67N

51N

(Same as other side) 51

86B

50 51

N.C. Note: Voltage transformers and voltage relays not shown 87TN also called Ref (Restricted Earth Fault) 87TN is an alternative 67N Add full bus differential for main substations

50GS

This information is considered CONFIDENTIAL and shall not be released to or discussed with any persons except (a) employees of ExxonMobil Affiliates who have an appropriate research agreement with ExxonMobil Research and Engineering Company (EMRE), and (b) consultants, contractors, or employees of third parties with whom proper secrecy agreements have been executed with EMRE or such ExxonMobil Affiliates. ExxonMobil Research and Engineering Company