Voltages and currents present at the generator's rated voltage and current are provided as examples. Sample relay setting calculations are shown for generator protection elements including 59N neutral overvoltage, 27TN third harmonic undervoltage, 46 negative sequence overcurrent, and coordination between protective devices. Formulas for calculating voltage and current settings from generator nameplate data are demonstrated.
This document provides guidelines for overcurrent protection and coordination settings for industrial equipment such as transformers, buses, feeders, and motors above 600V. It outlines typical recommended pickup and time delay settings as rules of thumb for phase and ground overcurrent relays protecting this equipment. Care must be taken to properly coordinate settings between protective devices to prevent unintended tripping and ensure equipment is protected against damage from faults.
�The sample calculations shown here illustrate steps involved in calculating the relay settings for generator protection.
�Other methodologies and techniques may be applied to calculate relay settings based on specific applications.
This document discusses transformer overcurrent protection calculations and settings. It provides information on:
1. Coordination principles for transformer protection and examples of typical protection zones for different fault locations.
2. Guidelines for setting instantaneous and time-overcurrent relays to ensure selective coordination, including maintaining coordination intervals.
3. Calculations for determining short circuit currents and relay settings for different transformer configurations, including delta-wye transformers. Thermal and mechanical withstand curves for different transformer categories are also presented.
This document discusses relay coordination and overcurrent protection. It begins with an introduction to relay coordination, covering the basic philosophy of selectivity, sensitivity and speed. It then discusses the need for protection coordination to ensure equipment safety, proper discrimination of faulty vs healthy portions of the power system, and reduced outage times. The document outlines various protection schemes including unit and non-unit schemes. It also covers overcurrent protection characteristics such as time-overcurrent, definite time, and instantaneous and provides examples of how relay trip times are calculated based on standards.
Practical handbook-for-relay-protection-engineersSARAVANAN A
The ‘Hand Book’ covers the Code of Practice in Protection Circuitry including standard lead and device numbers, mode of connections at terminal strips, colour codes in multicore cables, Dos and Donts in execution. Also, principles of various protective relays and schemes including special protection schemes like differential,
restricted, directional and distance relays are explained with sketches. The norms of protection of generators, transformers, lines & Capacitor Banks are also given.
Fundamentals of Power System protection by Y.G.Paithankar and S.R.BhideSourabh Ghosh
This document provides an overview of fundamentals of power system protection. It discusses various types of faults that can occur in power systems such as shunt faults, series faults, and abnormal operating conditions. It describes classification of faults and evolution of protection schemes from isolated to interconnected power systems. Various system transducers such as current transformers, potential transformers and circuit breakers are introduced. Principles of overcurrent, differential, distance and other protection schemes are outlined. Protection of transmission lines, transformers, buses, generators and motors are covered along with numerical protection and static comparators. The document aims to equip students with sound concepts of power system protection to handle real-life scenarios.
Tutorial on Distance and Over Current ProtectionSARAVANAN A
Contents
• Protection Philosophy of ERPC
• Computation of Distance Relay Setting
• System Study to Understand Distance Relay
Behaviour
• DOC and DEF for EHV system
Voltages and currents present at the generator's rated voltage and current are provided as examples. Sample relay setting calculations are shown for generator protection elements including 59N neutral overvoltage, 27TN third harmonic undervoltage, 46 negative sequence overcurrent, and coordination between protective devices. Formulas for calculating voltage and current settings from generator nameplate data are demonstrated.
This document provides guidelines for overcurrent protection and coordination settings for industrial equipment such as transformers, buses, feeders, and motors above 600V. It outlines typical recommended pickup and time delay settings as rules of thumb for phase and ground overcurrent relays protecting this equipment. Care must be taken to properly coordinate settings between protective devices to prevent unintended tripping and ensure equipment is protected against damage from faults.
�The sample calculations shown here illustrate steps involved in calculating the relay settings for generator protection.
�Other methodologies and techniques may be applied to calculate relay settings based on specific applications.
This document discusses transformer overcurrent protection calculations and settings. It provides information on:
1. Coordination principles for transformer protection and examples of typical protection zones for different fault locations.
2. Guidelines for setting instantaneous and time-overcurrent relays to ensure selective coordination, including maintaining coordination intervals.
3. Calculations for determining short circuit currents and relay settings for different transformer configurations, including delta-wye transformers. Thermal and mechanical withstand curves for different transformer categories are also presented.
This document discusses relay coordination and overcurrent protection. It begins with an introduction to relay coordination, covering the basic philosophy of selectivity, sensitivity and speed. It then discusses the need for protection coordination to ensure equipment safety, proper discrimination of faulty vs healthy portions of the power system, and reduced outage times. The document outlines various protection schemes including unit and non-unit schemes. It also covers overcurrent protection characteristics such as time-overcurrent, definite time, and instantaneous and provides examples of how relay trip times are calculated based on standards.
Practical handbook-for-relay-protection-engineersSARAVANAN A
The ‘Hand Book’ covers the Code of Practice in Protection Circuitry including standard lead and device numbers, mode of connections at terminal strips, colour codes in multicore cables, Dos and Donts in execution. Also, principles of various protective relays and schemes including special protection schemes like differential,
restricted, directional and distance relays are explained with sketches. The norms of protection of generators, transformers, lines & Capacitor Banks are also given.
Fundamentals of Power System protection by Y.G.Paithankar and S.R.BhideSourabh Ghosh
This document provides an overview of fundamentals of power system protection. It discusses various types of faults that can occur in power systems such as shunt faults, series faults, and abnormal operating conditions. It describes classification of faults and evolution of protection schemes from isolated to interconnected power systems. Various system transducers such as current transformers, potential transformers and circuit breakers are introduced. Principles of overcurrent, differential, distance and other protection schemes are outlined. Protection of transmission lines, transformers, buses, generators and motors are covered along with numerical protection and static comparators. The document aims to equip students with sound concepts of power system protection to handle real-life scenarios.
Tutorial on Distance and Over Current ProtectionSARAVANAN A
Contents
• Protection Philosophy of ERPC
• Computation of Distance Relay Setting
• System Study to Understand Distance Relay
Behaviour
• DOC and DEF for EHV system
Tan delta is the insulation power factor & is equal to the ratio of power dissipated in the insulation in watts to the product of effective voltage & current in volt ampere when tested under sinusoidal voltage.
The document discusses transformer protection. It describes various failures that can occur in transformers such as winding failures, bushing failures, and tap changer failures. It provides statistics on historical transformer failures. It also discusses different types of protection for transformers including electrical protection methods like differential protection, overcurrent protection, overexcitation protection and thermal protection. Internal short circuits, system short circuits, and abnormal conditions are some of the issues addressed by transformer protection schemes.
This document provides an overview of a training session on protection fundamentals presented by Craig Wester and John Levine of GE Multilin. The training covers protection tools, demonstration relays, future training classes, and protection fundamentals. The fundamentals section discusses desirable protection attributes, selection of protective relays, primary equipment components, and various types of protection including overcurrent, differential, voltage, frequency, power, and distance protection. Information required for applying protection is also listed.
This document discusses transformer sizing using ETAP software. It explains that ETAP takes into account factors like ambient temperature, altitude, cooling type and expected future growth to determine the proper transformer size. The document provides details on ETAP's 2-winding transformer sizing module, which calculates the rated MVA, maximum MVA and impedance based on loading, installation factors and short circuit requirements. It also discusses how ETAP can be used to check transformer regulation during motor starts. The document concludes that transformer sizing calculations can be standardized using ETAP due to the harmony between ETAP's sizing module and manual calculations using formulas.
The document discusses generator protection systems. It introduces the basic electrical quantities used for protection like current, voltage, phase angle and frequency. Protective relays use one or more of these quantities to detect faults. The document then discusses different types of relays and circuit breakers used for protection. It describes various protection zones like generator, transformer, bus, line and utilization equipment zones. The rest of the document elaborates on different protection schemes for generators including stator protection, rotor protection, loss of excitation protection and reverse power protection.
The document discusses generator protection and distance protection. It provides setting criteria for distance protection zones when used for generator backup protection, including setting Zone 1 to 80% of the generator step-up transformer and Zone 2 to 120% of the generator step-up transformer or to overreach the remote bus. It also discusses using Zone 3 for out-of-step blocking or overreaching the remote bus for system fault backup protection.
Generator Protection By - Er Rahul Sharma Rahul Ruddra
This document discusses generator protection systems. It describes how differential protection uses CTs to detect faults by measuring differences in current. Modified differential protection is discussed as a way to protect the full winding. Other protections mentioned include restricted earth fault protection, stator protection against phase and interturn faults, rotor earth fault protection using dc injection, loss of excitation detection, overload protection using temperature sensors, and negative sequence protection to prevent rotor overheating. The conclusion emphasizes that protective relays act after a fault occurs to ensure safety and equipment protection.
This document discusses transformer sizing methods in ETAP software based on industry standards. It describes how ETAP considers factors like cooling type, altitude, temperature, load variation, and impedance requirements to calculate the required transformer MVA size. The sizing results section shows the required size along with the next standard larger and smaller sizes. The ratings are automatically updated when clicking buttons in the transformer rating page. The document also covers unit transformer sizing in ETAP to optimize tap settings considering voltage variation and auxiliary loads.
The document discusses motor protection and motor control centers. It provides details on sizing conductors that supply single and multiple motors, sizing overload protection devices based on motor nameplate ratings, and protecting motors from short circuits and ground faults. It also describes the components, construction, and wiring classifications of motor control centers, which are used to control and provide protection for motors and connecting cables.
This document summarizes key principles of overcurrent protection and selectivity in electrical power systems. It discusses:
1) The goal of protection schemes is for the device closest to a fault to operate quickly while allowing other parts of the system to remain powered.
2) Achieving complete selectivity where protection curves do not overlap is difficult and economic compromises are often made.
3) New challenges include requirements for selective emergency systems and reducing arc flash hazards through faster fault clearing times.
This document discusses power transformer protection. It begins by explaining that transformers are static devices that transform electrical energy between circuits without changing frequency. Power transformers are vital but expensive components that are difficult to repair if damaged. Protection is needed to prevent severe damage from faults.
It then describes the types of faults as incipient, internal, or external. Potential causes of faults are listed as insulation breakdown, overheating, oil contamination, reduced cooling, and phase/ground faults.
The document outlines the general scheme of differential protection and lists specific protection functions used. It provides an example calculation for setting a transformer differential relay and describes the relay's operating characteristics. Models of differential protection relays from various manufacturers are also listed.
The document discusses transformer protection. It describes different types of faults that can occur in transformers, both internal and external. It then discusses various protection methods for transformers, including differential protection, sudden pressure relays, overcurrent protection, and thermal protection. It also provides details on magnetizing inrush current and how it is influenced by factors like transformer size, system resistance, and residual flux levels.
The following topics are covered: components of power distribution systems, fuses, padmounted transformers, pole mounted transformers, vault installed transformers, transformer stations protection, transformer connections, thermometers, pressure relief devices, restricted ground faults, differential protection current transformers connections, overexcitation, inrush current, percentage differential relays, gas relays, characteristics of CTs.
This document provides an agenda and overview for a two-day seminar on overcurrent protection and coordination for industrial applications. Day 1 will cover topics such as the information required for coordination, time-current curves, fault currents, protective devices and coordination time intervals. Day 2 will focus on overcurrent protection for specific equipment such as transformers, motors, conductors and generators. The presenter's biography is provided, noting his engineering experience in power system planning and protection, including serving as an assistant technical editor for an IEEE standard on overcurrent protection.
Sample calculation-for-differential-relaysRoberto Costa
The document provides calculations for setting differential relays on a power transformer. It includes calculations of currents at different transformer taps to determine relay settings that avoid unwanted operation during tap changes. Currents are calculated for the high voltage side, low voltage side and on the relay at extremes of +/- 10% taps. The differential current at each tap is compared to the relay operating current to set the pickup value to avoid operation during tap changes while maintaining protection.
A presentation explaining how to calculate fault currents for 3-phase or 1-phase faults in power grid. Particularly useful for engineers working in electrical power transmission company.
This document provides information on the MJE13003 NPN silicon transistor from Unisonic Technologies Co., Ltd. It describes the transistor as being designed for high-voltage, high-speed power switching in inductive circuits. Key features include a reverse biased safe operating area with inductive loads up to 1.5 amps and a typical fall time of 290ns at 1 amp and 100°C. The transistor has applications in switching regulators, inverters, motor controls, solenoid drivers, and deflection circuits. Electrical characteristics and maximum ratings are provided in tables and graphs.
Tan delta is the insulation power factor & is equal to the ratio of power dissipated in the insulation in watts to the product of effective voltage & current in volt ampere when tested under sinusoidal voltage.
The document discusses transformer protection. It describes various failures that can occur in transformers such as winding failures, bushing failures, and tap changer failures. It provides statistics on historical transformer failures. It also discusses different types of protection for transformers including electrical protection methods like differential protection, overcurrent protection, overexcitation protection and thermal protection. Internal short circuits, system short circuits, and abnormal conditions are some of the issues addressed by transformer protection schemes.
This document provides an overview of a training session on protection fundamentals presented by Craig Wester and John Levine of GE Multilin. The training covers protection tools, demonstration relays, future training classes, and protection fundamentals. The fundamentals section discusses desirable protection attributes, selection of protective relays, primary equipment components, and various types of protection including overcurrent, differential, voltage, frequency, power, and distance protection. Information required for applying protection is also listed.
This document discusses transformer sizing using ETAP software. It explains that ETAP takes into account factors like ambient temperature, altitude, cooling type and expected future growth to determine the proper transformer size. The document provides details on ETAP's 2-winding transformer sizing module, which calculates the rated MVA, maximum MVA and impedance based on loading, installation factors and short circuit requirements. It also discusses how ETAP can be used to check transformer regulation during motor starts. The document concludes that transformer sizing calculations can be standardized using ETAP due to the harmony between ETAP's sizing module and manual calculations using formulas.
The document discusses generator protection systems. It introduces the basic electrical quantities used for protection like current, voltage, phase angle and frequency. Protective relays use one or more of these quantities to detect faults. The document then discusses different types of relays and circuit breakers used for protection. It describes various protection zones like generator, transformer, bus, line and utilization equipment zones. The rest of the document elaborates on different protection schemes for generators including stator protection, rotor protection, loss of excitation protection and reverse power protection.
The document discusses generator protection and distance protection. It provides setting criteria for distance protection zones when used for generator backup protection, including setting Zone 1 to 80% of the generator step-up transformer and Zone 2 to 120% of the generator step-up transformer or to overreach the remote bus. It also discusses using Zone 3 for out-of-step blocking or overreaching the remote bus for system fault backup protection.
Generator Protection By - Er Rahul Sharma Rahul Ruddra
This document discusses generator protection systems. It describes how differential protection uses CTs to detect faults by measuring differences in current. Modified differential protection is discussed as a way to protect the full winding. Other protections mentioned include restricted earth fault protection, stator protection against phase and interturn faults, rotor earth fault protection using dc injection, loss of excitation detection, overload protection using temperature sensors, and negative sequence protection to prevent rotor overheating. The conclusion emphasizes that protective relays act after a fault occurs to ensure safety and equipment protection.
This document discusses transformer sizing methods in ETAP software based on industry standards. It describes how ETAP considers factors like cooling type, altitude, temperature, load variation, and impedance requirements to calculate the required transformer MVA size. The sizing results section shows the required size along with the next standard larger and smaller sizes. The ratings are automatically updated when clicking buttons in the transformer rating page. The document also covers unit transformer sizing in ETAP to optimize tap settings considering voltage variation and auxiliary loads.
The document discusses motor protection and motor control centers. It provides details on sizing conductors that supply single and multiple motors, sizing overload protection devices based on motor nameplate ratings, and protecting motors from short circuits and ground faults. It also describes the components, construction, and wiring classifications of motor control centers, which are used to control and provide protection for motors and connecting cables.
This document summarizes key principles of overcurrent protection and selectivity in electrical power systems. It discusses:
1) The goal of protection schemes is for the device closest to a fault to operate quickly while allowing other parts of the system to remain powered.
2) Achieving complete selectivity where protection curves do not overlap is difficult and economic compromises are often made.
3) New challenges include requirements for selective emergency systems and reducing arc flash hazards through faster fault clearing times.
This document discusses power transformer protection. It begins by explaining that transformers are static devices that transform electrical energy between circuits without changing frequency. Power transformers are vital but expensive components that are difficult to repair if damaged. Protection is needed to prevent severe damage from faults.
It then describes the types of faults as incipient, internal, or external. Potential causes of faults are listed as insulation breakdown, overheating, oil contamination, reduced cooling, and phase/ground faults.
The document outlines the general scheme of differential protection and lists specific protection functions used. It provides an example calculation for setting a transformer differential relay and describes the relay's operating characteristics. Models of differential protection relays from various manufacturers are also listed.
The document discusses transformer protection. It describes different types of faults that can occur in transformers, both internal and external. It then discusses various protection methods for transformers, including differential protection, sudden pressure relays, overcurrent protection, and thermal protection. It also provides details on magnetizing inrush current and how it is influenced by factors like transformer size, system resistance, and residual flux levels.
The following topics are covered: components of power distribution systems, fuses, padmounted transformers, pole mounted transformers, vault installed transformers, transformer stations protection, transformer connections, thermometers, pressure relief devices, restricted ground faults, differential protection current transformers connections, overexcitation, inrush current, percentage differential relays, gas relays, characteristics of CTs.
This document provides an agenda and overview for a two-day seminar on overcurrent protection and coordination for industrial applications. Day 1 will cover topics such as the information required for coordination, time-current curves, fault currents, protective devices and coordination time intervals. Day 2 will focus on overcurrent protection for specific equipment such as transformers, motors, conductors and generators. The presenter's biography is provided, noting his engineering experience in power system planning and protection, including serving as an assistant technical editor for an IEEE standard on overcurrent protection.
Sample calculation-for-differential-relaysRoberto Costa
The document provides calculations for setting differential relays on a power transformer. It includes calculations of currents at different transformer taps to determine relay settings that avoid unwanted operation during tap changes. Currents are calculated for the high voltage side, low voltage side and on the relay at extremes of +/- 10% taps. The differential current at each tap is compared to the relay operating current to set the pickup value to avoid operation during tap changes while maintaining protection.
A presentation explaining how to calculate fault currents for 3-phase or 1-phase faults in power grid. Particularly useful for engineers working in electrical power transmission company.
This document provides information on the MJE13003 NPN silicon transistor from Unisonic Technologies Co., Ltd. It describes the transistor as being designed for high-voltage, high-speed power switching in inductive circuits. Key features include a reverse biased safe operating area with inductive loads up to 1.5 amps and a typical fall time of 290ns at 1 amp and 100°C. The transistor has applications in switching regulators, inverters, motor controls, solenoid drivers, and deflection circuits. Electrical characteristics and maximum ratings are provided in tables and graphs.
Original Opto LTV-354T LTV354T 354T 354 SOP-4 NewAUTHELECTRONIC
This document provides product data and specifications for Lite-On Technology Corp.'s LTV-354T series photocouplers. It includes details on packaging, electrical and optical characteristics, temperature profiles for soldering, and recommended footprints. The photocouplers feature AC input response, high isolation voltage up to 3,750Vrms, and mini-flat packages as small as 2.0mm in profile. They are suitable for applications requiring high density mounting such as hybrid substrates, programmable controllers, and measuring instruments.
This document provides details about the installation, testing, and commissioning of an 800 KVA sub-station at Euro Tech Bangladesh. It includes a single line diagram and layout of the sub-station, descriptions of the equipment used including the transformer, switchgear, capacitor bank, and earthing system. Test results like the transformer meggar test and earthing test are also presented. Recommendations are provided to ensure proper maintenance and safety of the sub-station.
The document describes the UCC3895 BiCMOS advanced phase-shift PWM controller. It has features such as programmable output turn-on delay, adaptive delay set, bidirectional oscillator synchronization, and voltage-mode or current-mode control. It can operate at frequencies up to 1 MHz with typical operating current of 5 mA at 500 kHz. The UCC3895 is a phase-shift PWM controller that implements full-bridge power stage control by phase shifting one half-bridge with respect to the other, allowing constant frequency pulse-width modulation with zero-voltage switching for high efficiency at high frequencies. It improves on previous controller families with additional features such as enhanced control logic and adaptive delay set.
Hitachi's Service Proven Automotive IGBT MBB600TV6A at 600A / 650V with Direc...Juan Munoz
Hitachi introduces new EV and HEV IGBT MBB600TV6A (650V 600A 6 in 1), which more than 300,000 units have been sold successfully in Japan already, making it proven technology.
*Soon bringing the Temperature sensor on IGBT chip: MBB800TW6A (650V 800A 6 in 1).
--------------------------------------------------------------------------------------------------------------------------------
Hitachi Power Semiconductor Devices Direct Pin Liquid Cooling Technology has been applied on more than 600,000 units and is continuously improving with new units to hit the market rated at 800A this year and 1000A later on.
Among some of the features are:
• High speed, low loss IGBT module
• Low thermal impedance due to direct liquid cooling
• High reliability, high durability module
• Operating Junction Temperatures range from -50*C to +150*C
• Small footprint 163x94 mm package
• Three thermistor sensors, one per each phase leg
• Compact and stable sealing structure and thermal grease‐free
The Hitachi’s Direct Pin Liquid Cooling IGBTs offers (1) low thermal resistance realized by thermal-greaseless “direct-liquid-cooling” technology with pin-fin, whose pressure drop and fin efficiency are optimally designed, (2) small package size, which enables compact power conditioner system, (3) high reliability and long lifetime realized by high strength Si3N4 insulated substrate and newly developed RoHS bonding technologies. The thermal resistance Rj-w of the IGBT module is reduced by 35 percent when compared to “indirect-cooling” conventional modules using thermal grease. The developed IGBT module and channel cover jacket are approximately 37 percent lighter and 45 percent smaller when compared to conventional modules with the same power capability.
Applications
• EV / HEV / PHEV
• Commercial Electric Vehicles
This document provides an overview of the electrical system and equipment at the NTPC Lara power plant. It includes a breakdown of the major components in the switchyard, generators, transformers, motors, and switchgears at various voltage levels. Diagrams show the single line diagrams and connections between units, transformers, and switchgears. It also includes specifications of the main equipment such as generators, transformers, circuit breakers and motors.
Original Digital Transistor KRC105 C105M C105 100mA 50V TO-92 NewAUTHELECTRONIC
This document provides specifications for 6 types of epitaxial planar NPN transistors (KRC101-KRC106). The transistors have built-in bias resistors to simplify circuit design. Key specifications include maximum voltage and current ratings, electrical characteristics like DC current gain and switching times, and I-V and G-I curves showing performance over temperature ranges.
Original NPN Transistor KRC106M C106 106 TO-92 New KECAUTHELECTRONIC
This document provides specifications for 6 types of epitaxial planar NPN transistors (KRC101-KRC106). The transistors have built-in bias resistors to simplify circuit design. Key specifications include maximum voltage and current ratings, electrical characteristics like DC current gain and switching times, and I-V and G-I curves showing performance over temperature ranges.
This document provides information on the RT7257E, a 3A synchronous step-down DC-DC converter. It can deliver up to 3A of output current from an input supply of 4.5V to 17V and has a fixed switching frequency of 340kHz. The converter uses current mode control and has features such as cycle-by-cycle current limiting, soft-start, and thermal shutdown protection. It is available in an SOP-8 package and is suitable for applications such as wireless routers, LCD monitors, and green electronics.
Original N-Channel Mosfet 2SK3484 3484 16A 100V TO-252 New Renesas ElectronicsAUTHELECTRONIC
This document provides specifications for the 2SK3484 N-channel MOS field effect transistor (MOSFET) including:
- Electrical characteristics such as on-state resistance, gate cut-off voltage, and input/output capacitances.
- Thermal characteristics such as thermal resistance and power dissipation derating curves.
- Switching characteristics such as turn-on/off delay times and rise/fall times.
- Package drawings and equivalent circuit diagram for the TO-251 and TO-252 packages.
This document outlines the minimum acceptable specifications for current transformers, potential transformers, and capacitor voltage transformers used for metering purposes at different voltage levels.
The specifications include parameters such as highest system voltage, transformer ratios, number of cores/windings, rated thermal and short circuit currents, accuracy classes, voltage and burden ratings that the transformers must conform to for different voltage levels ranging from 11kV to 245kV.
The document also specifies the applicable Indian Standards that the transformers and their insulating oils must conform to for metering applications.
Original PNP Transistors PZT2907A PZT2907 2907 P2F SOT22-3 New On Semiconductorauthelectroniccom
This document provides information on three general purpose transistors - the PN2907A, MMBT2907A, and PZT2907A. It describes their key electrical and thermal characteristics such as current gain range, maximum ratings, and package options. Diagrams of their physical dimensions and typical performance curves are also included. The transistors are designed for use as amplifiers or switches in applications requiring up to 500mA of current.
Original N-Channel Mosfet 7N65L-TF1-T UTC7N65L 7.4A 650V TO-263 New UTCAUTHELECTRONIC
The 7N65 power MOSFET from Unisonic Technologies is a high-voltage transistor designed for switching applications. It has a maximum voltage rating of 650V, continuous current rating of 7.4A, and features low on-resistance, fast switching times, and high ruggedness. The document provides detailed specifications, characteristics, test methods and typical performance curves for the device.
Earth Leakage Relay | Motor Protection Relay - GIC IndiaPrasadPurohit1988
GIC’s manufacture earth leakage relay that innovative product monitors and detects Earth leakage faults so as to protect your power systems and equipment.
Original IGBT Transistor IHW25N1202R2 H25R1202 25A 1200V TO-247 New Infineon ...AUTHELECTRONIC
This document provides specifications for the IHW25N120R2 reverse conducting IGBT module. Key details include:
- It has a 1200V blocking voltage and maximum current of 25A.
- Features include a low forward voltage body diode, trench and fieldstop technology for tight parameters, and NPT technology for easy parallel switching.
- Maximum ratings and thermal/switching characteristics are provided for different operating conditions.
- Applications include inductive cooking and soft switching applications.
Similar to RELAY ETTING CALCULATION REV-A (DG-298).pdf (20)
Using recycled concrete aggregates (RCA) for pavements is crucial to achieving sustainability. Implementing RCA for new pavement can minimize carbon footprint, conserve natural resources, reduce harmful emissions, and lower life cycle costs. Compared to natural aggregate (NA), RCA pavement has fewer comprehensive studies and sustainability assessments.
DEEP LEARNING FOR SMART GRID INTRUSION DETECTION: A HYBRID CNN-LSTM-BASED MODELgerogepatton
As digital technology becomes more deeply embedded in power systems, protecting the communication
networks of Smart Grids (SG) has emerged as a critical concern. Distributed Network Protocol 3 (DNP3)
represents a multi-tiered application layer protocol extensively utilized in Supervisory Control and Data
Acquisition (SCADA)-based smart grids to facilitate real-time data gathering and control functionalities.
Robust Intrusion Detection Systems (IDS) are necessary for early threat detection and mitigation because
of the interconnection of these networks, which makes them vulnerable to a variety of cyberattacks. To
solve this issue, this paper develops a hybrid Deep Learning (DL) model specifically designed for intrusion
detection in smart grids. The proposed approach is a combination of the Convolutional Neural Network
(CNN) and the Long-Short-Term Memory algorithms (LSTM). We employed a recent intrusion detection
dataset (DNP3), which focuses on unauthorized commands and Denial of Service (DoS) cyberattacks, to
train and test our model. The results of our experiments show that our CNN-LSTM method is much better
at finding smart grid intrusions than other deep learning algorithms used for classification. In addition,
our proposed approach improves accuracy, precision, recall, and F1 score, achieving a high detection
accuracy rate of 99.50%.
We have compiled the most important slides from each speaker's presentation. This year’s compilation, available for free, captures the key insights and contributions shared during the DfMAy 2024 conference.
CHINA’S GEO-ECONOMIC OUTREACH IN CENTRAL ASIAN COUNTRIES AND FUTURE PROSPECTjpsjournal1
The rivalry between prominent international actors for dominance over Central Asia's hydrocarbon
reserves and the ancient silk trade route, along with China's diplomatic endeavours in the area, has been
referred to as the "New Great Game." This research centres on the power struggle, considering
geopolitical, geostrategic, and geoeconomic variables. Topics including trade, political hegemony, oil
politics, and conventional and nontraditional security are all explored and explained by the researcher.
Using Mackinder's Heartland, Spykman Rimland, and Hegemonic Stability theories, examines China's role
in Central Asia. This study adheres to the empirical epistemological method and has taken care of
objectivity. This study analyze primary and secondary research documents critically to elaborate role of
china’s geo economic outreach in central Asian countries and its future prospect. China is thriving in trade,
pipeline politics, and winning states, according to this study, thanks to important instruments like the
Shanghai Cooperation Organisation and the Belt and Road Economic Initiative. According to this study,
China is seeing significant success in commerce, pipeline politics, and gaining influence on other
governments. This success may be attributed to the effective utilisation of key tools such as the Shanghai
Cooperation Organisation and the Belt and Road Economic Initiative.
Literature Review Basics and Understanding Reference Management.pptxDr Ramhari Poudyal
Three-day training on academic research focuses on analytical tools at United Technical College, supported by the University Grant Commission, Nepal. 24-26 May 2024
Harnessing WebAssembly for Real-time Stateless Streaming PipelinesChristina Lin
Traditionally, dealing with real-time data pipelines has involved significant overhead, even for straightforward tasks like data transformation or masking. However, in this talk, we’ll venture into the dynamic realm of WebAssembly (WASM) and discover how it can revolutionize the creation of stateless streaming pipelines within a Kafka (Redpanda) broker. These pipelines are adept at managing low-latency, high-data-volume scenarios.
Electric vehicle and photovoltaic advanced roles in enhancing the financial p...IJECEIAES
Climate change's impact on the planet forced the United Nations and governments to promote green energies and electric transportation. The deployments of photovoltaic (PV) and electric vehicle (EV) systems gained stronger momentum due to their numerous advantages over fossil fuel types. The advantages go beyond sustainability to reach financial support and stability. The work in this paper introduces the hybrid system between PV and EV to support industrial and commercial plants. This paper covers the theoretical framework of the proposed hybrid system including the required equation to complete the cost analysis when PV and EV are present. In addition, the proposed design diagram which sets the priorities and requirements of the system is presented. The proposed approach allows setup to advance their power stability, especially during power outages. The presented information supports researchers and plant owners to complete the necessary analysis while promoting the deployment of clean energy. The result of a case study that represents a dairy milk farmer supports the theoretical works and highlights its advanced benefits to existing plants. The short return on investment of the proposed approach supports the paper's novelty approach for the sustainable electrical system. In addition, the proposed system allows for an isolated power setup without the need for a transmission line which enhances the safety of the electrical network
A review on techniques and modelling methodologies used for checking electrom...nooriasukmaningtyas
The proper function of the integrated circuit (IC) in an inhibiting electromagnetic environment has always been a serious concern throughout the decades of revolution in the world of electronics, from disjunct devices to today’s integrated circuit technology, where billions of transistors are combined on a single chip. The automotive industry and smart vehicles in particular, are confronting design issues such as being prone to electromagnetic interference (EMI). Electronic control devices calculate incorrect outputs because of EMI and sensors give misleading values which can prove fatal in case of automotives. In this paper, the authors have non exhaustively tried to review research work concerned with the investigation of EMI in ICs and prediction of this EMI using various modelling methodologies and measurement setups.
Embedded machine learning-based road conditions and driving behavior monitoringIJECEIAES
Car accident rates have increased in recent years, resulting in losses in human lives, properties, and other financial costs. An embedded machine learning-based system is developed to address this critical issue. The system can monitor road conditions, detect driving patterns, and identify aggressive driving behaviors. The system is based on neural networks trained on a comprehensive dataset of driving events, driving styles, and road conditions. The system effectively detects potential risks and helps mitigate the frequency and impact of accidents. The primary goal is to ensure the safety of drivers and vehicles. Collecting data involved gathering information on three key road events: normal street and normal drive, speed bumps, circular yellow speed bumps, and three aggressive driving actions: sudden start, sudden stop, and sudden entry. The gathered data is processed and analyzed using a machine learning system designed for limited power and memory devices. The developed system resulted in 91.9% accuracy, 93.6% precision, and 92% recall. The achieved inference time on an Arduino Nano 33 BLE Sense with a 32-bit CPU running at 64 MHz is 34 ms and requires 2.6 kB peak RAM and 139.9 kB program flash memory, making it suitable for resource-constrained embedded systems.
1. CERT'D
AYK
APP'D
OB
NO.
A
BY:-
DATE:-
BY:-
DATE:-
BY
DATE:-
BY:-
DATE:-
BY:-
DATE:- AS BUILT BY DATE
INDEX PLANT REV.
1-113045.01 DWG.CON. SHT. EE-221387
THIS DRAWING IS NOT
TO BE USED FOR
CONSTRUCTION OF
FOR ORDERING
MATERIALS UNTIL
CERTIFIED AND
DATED
DOCUMENT TITLE
RELAY SETTING CALCULATION
A
QATIF 115/13.8 KV SUBSTATION NO. 2
QATIF SAUDI ARABIA JOB ORDER NO.
DOCUMENT NO. SHEET NO.
RELAY SETTING CALCULATION
A DA441 EE-221424 01 OF 54
ENG'G. DEPT.
CERTIFIED.
للكھرباء السعودية الشركة
الشرقية المنطقة فرع
CHEK'D
SA
Saudi Electricity Company
Eastern Region Branch
DESCRIPTION
FIRST
ISSUE
BY
DAR
REVISIONS
DESIGNED
SA
10/2013
OPRG. DEPT
DATE
10/2013
CHECKED
OB
10/2013
2. DOC. NO.
Rev.
1
1.1 REB500 (87BB) 5
2
2.1 RET670 (87T) 6
2.2 MCAG14 (87REF) 8
2.3 P142 (50/51) 10
2.4 P142 (67/67N) 11
2.5 P142 (50N/51N) 12
2.6 P142 (67LV-N) 3
2.7 P142 (51G) 14
3
PHASE FAULT
3.1 115KV BUS COUPLER O/C RELAY P142 (51BC) 15
EARTH FAULT
3.2 P142 (51BC-N) 16
4
PHASE FAULT
4.1 115KV BUS SECTION O/C RELAY P142 (51BS) 17
EARTH FAULT
4.2 P142 (51BS-N) 18
5
5.1 RED670 (21/87/67-1/67N-1) 19
5.2 P546 (21/87/67N-1) 29
115/13.8 KV TRANSFORMER DIFFERENTIAL PROTECTION RELAY SETTING
380/115 KV TRANSFORMER DIRECTIONAL E/F PROTECTION RELAY LV-N
PHASE FAULT
115KV BUS COUPLER O/C PROTECTION RELAY SETTING
115/13.8KV POWER TRANSFORMER PROTECTION
115KV BUS SECTION O/C PROTECTION RELAY SETTING
EE-221424
115KV BB/BF PROTECTION RELAY SETTING
115KV BUS SECTION E/F O/C RELAY
115/13.8 KV TRANSFORMER LV DIRECTIONAL O/C PROTECTION RELAY
115KV LINE PROTECTION RELAY SETTING
INDEX
115/13.8 KV TRANSFORMER LV NEUTRAL O/C PROTECTION RELAY
STATION QATIF 115/13.8KV SUBSTATION NO. 2 A
DOCUMENT: RELAY SETTING CALCULATION
Page No
DESCRIPTION
SECTION
115KV BB DIFFERENTIAL PROTECTION (WITH BUILT IN BF) RELAY
SETTING
EARTH FAULT
115/13.8 KV TRANSFORMER HV NON DIRECTIONAL E/F O/C PROTECTION
RELAY HV
115/13.8 KV TRANSFORMER RESTRICTED EARTH FAULT PROTECTION
RELAY SETTING
115/13.8 KV TRANSFORMER HV NON DIRECTIONAL O/C PROTECTION
RELAY HV
115KV BUS COUPLER E/F O/C RELAY
115KV NEW QATIF U/G CABLE 1,2,3 & 4 PROTECTION SET-1 RELAY SETTING
(will be sumitted later after receiving measured line parameters)
115KV NEW QATIF U/G CABLE 1,2,3 & 4 PROTECTION SET-2 RELAY SETTING
(will be sumitted later after receiving measured line parameters)
2
3. DOC. NO.
Rev.
6
PHASE FAULT
6.1 13.8KV STATION SERVICE TRANSFORMER FEEDER O/C RELAY REF615 (50/51) 36
EARTH FAULT
6.2 REF615 (50N/51N) 37
7
PHASE FAULT
7.1 REF615 (50/51) 38
EARTH FAULT
7.2 REF615 (50N/51N) 39
8
PHASE FAULT
8.1 13.8KVBUS SECTION O/C RELAY REF615 (50/51) 40
EARTH FAULT
8.2 REF615 (50N/51N) 41
9
9.1 Capacitor bank neutral un-balance setting MICOM-P142 42
9.2 13.8kV Capacitor bank inst PH O/C protection (50PA, 50PB & 50PC) ABB-RXIG22 43
9.3 13.8kV Capacitor bank INST E/F protection-RXIG22 (50PN) ABB-RXIG22 44
9.4 13.8kV Capacitor bank IDMT PH O/C protection MICOM-P142 45
9.5 13.8kV Capacitor bank IDMT E/F protection MICOM-P142 46
9.6 13.8kV Capacitor bank O/V protection 59-1 MICOM-P922 47
9.7 13.8kV Capacitor bank O/V protection 59-2 MICOM-P922 48
9.8 13.8kV Capacitor bank U/V protection MICOM-P922 49
10
10.1 13.8KV BUSBAR PROTECTION RELAY SETTING MCAG14 50
10.2 MVTP11 52
13.8KV BUS SECTION EARTH FAULT RELAY
INDEX
13.8KV BUSBAR PROTECTION RELAY SETTING
13.8KV BUSBAR PROTECTION HIGH IMPEDANCE CT SUPERVISION RELAY
DESCRIPTION
13.8KV STATION SERVICE TRANSFORMER FEEDER PROTECTION
EE-221424
STATION QATIF 115/13.8KV SUBSTATION NO. 2 A
13.8KV CAPACITOR BANK RELAY SETTING
SECTION Page No
13.8KV OUTGOING FEEDER E/F O/C RELAY
13.8KV OUTGOING FEEDER O/C RELAY
13.8KV STATION SERVICE TRANSFORMER FEEDER EARTH FAULT RELAY
DOCUMENT:
13.8KV BUS SECTION PROTECTION
13.8KV OUTGOING FEEDER PROTECTION
RELAY SETTING CALCULATION
3
4. DOC. NO.
Rev.
11
11.1 115KV BCU SYNCHROCHECK FUNCTION SETTING REC670 53
12 TRANSFORMER AVR SETTING
12.1 TAPCON260 54
Annexure-A : Relay and Metering One Line Diagram
Annexure-B : Relay Coordination graphs and ETAP file
Annexure-C : Relay Ordering No.
Annexure-D : Transformer Data and Fault Level Data
Annexure-E : Other Information
Annexure-F : Relay Confoguration Files in PDF format
115/13.8 KV POWER TRANSFORMER AVR SETTING
DOCUMENT: RELAY SETTING CALCULATION
SECTION DESCRIPTION Page No
STATION
EE-221424
115KV BCU SYNCHROCHECK FUNCTION SETTING
QATIF 115/13.8KV SUBSTATION NO. 2 A
INDEX
4
5. 1.1 115KV BUSBAR DIFFERENTIAL PROTECTION (WITH BUILT IN BF) RELAY SETTING (REB 500)
Circuit
Ref :
Relay
Designation
Relay
Type
Make ABB Doc. Ref
Aux.
Voltage
CT Ratio PT Ratio
Nominal
Current
Rated Voltage Freq
CT Data
CT Ratio : Primary 3000 A Adopted tap
: Secondary 1 A 2000 A
Class TPS
CT Knee Point Voltage (Vkp) 1666.6 V
Magnetising current IM at Vkp 30 mA
CT Secondary resistance RCT 3.13 Ohms
Ik min 1000
Op char. L1,L2.L3 1000 A
k Op char. L1,L2.L3 0.8
Diff. current Alarm c Op char. L1,L2.L3 10 % I kmin
Delay Op char. L1,L2.L3 5 S
Ik min 1000
Op char. L0 300 A
k Op char. L0 0.8
Diff. current Alarm c Op char. L0 10 % I kmin
Delay Op char. L0 10 s
Breaker Failure Protection
BFP Active Active
Setting (per CT) 1.2 In
Timer 1 Active Active
Ttimer 2 Active Active
Timer 1 100 ms
Ttimer 2 150 ms
Inter trip pulse Duration 200 ms
Logic type 1
EE-221424
A
DOCUMENT: Doc. No.:
STATION: Rev. No.:
RELAY SETTING CALCULATION
QATIF 115/13.8KV SUBSTATION NO.2
REB500
60HZ
Bus 1A,1B,2A,2B
and check zone
125 V DC
1A
87B+50BF
2000/1 _
QATIF 115/13.8KV
SUBSTATION NO. 2 5
RELAY SETTING
REV.A
6. Document Title: DOC. NO.
Substation: Rev. No.
2.1 115/13.8KV Power Transformer Differential Protection
Circuit
Ref :
Relay
Designation
Relay
Type
Make ABB Doc. Ref
Aux.
Voltage
CT Ratio
Relay
order #
Nominal
Current
Rated
Voltage
Freq
HV MV Remarks
Voltage Ratio 115 / 13.8 kV
Connection D / y
Vector group
Rating ONAN 50 / 50 MVA
Rating ONAF 67 / 67 MVA
OLTC Type
Highest tap 1 129.38 kV
Nominal tap 11 115 kV Nominal tap
Lowest tap 27 92 kV
Rated Current @ 67 MVA at Highest tap= MVA*1000/SQRT(3) x KV
299 A
Rated Current @ 67 MVA at Nominal tap= MVA*1000/SQRT(3) x KV
336 A
Rated Current @ 67 MVA at Lowest tap = MVA*1000/SQRT(3) x KV
420 A
% Impedance on 50MVA Base HV-MV HV-TV MV-TV
Positive Sequence Impedance, Tap 1 23.60% - -
Positive Sequence Impedance, Tap 11 22.00% - - Nominal tap
Positive Sequence Impedance, Tap 27 22.30% - -
Transformer HV side CT ratio 3000 / 1 A MRCT
Adopted tap 500 / 1 A
Rated HV Side. current @67MVA 336 A
500/1A
RET670 *1.2-B40X00-D02-D04P01-
01-C-B-K-B-B-B3-DAXE
_
OLTC range 115 (+10 to -16) x 1.25%kV
RET670
60HZ
T601, T602 & T603
125 V DC
1A
87T / T601
87T / T602
87T / T603
EE-221424
A
RELAY SETTING CALCULATION
QATIF 115/13.8KV SUBSTATION NO.2
Dyn1
Calculation for Transformer Differential Protection 87T settings :
QATIF 115/13.8kV
SUBSTATION NO.2 6
RELAY SETTING
Rev.A
7. Document Title: DOC. NO.
Substation: Rev. No.
EE-221424
A
RELAY SETTING CALCULATION
QATIF 115/13.8KV SUBSTATION NO.2
Transformer MV side CT ratio 4000 / 1 A DRCT
Adopted tap 4000 / 1 A
Rated Sec. current @ 67MVA 2803.1 A
Maximum current error due to OLTC (26 taps x 1.25%) = 32.5 %
Setting Parameter for Differential protection DIFP
Unit
KV
KV
KV
A
A
A
-
-
-
ClockNumberW1 deg
-
-
-
-
-
-
-
-
-
%
% of Ir
% of Ir
%
%
-
TV rating voltage
-
RatedVoltageW3
RatedCurrentW3
--
-- TV rating current
-
-- 2803
RatedVoltageW2 -- 13.8 MV rating voltage
RatedCurrentW2
27 the highest Tap position
Winding1 (W1) Tap Changer location
LowTapPosOLTC1
StepSizeOLTC1 -- 1.25% max. resolution of Tap
TapLowVoltTC1 -- 5
-- 1 the lowest Tap position
On/Off Off
TconfigForW2 On/Off Off
wye (y) MV side connection type
-- 1 [30 deg lag] clock number
ConnectTypetW3
--
MV rating current
DELTA (D)
--
HV side connection type
ConnectTypetW2
ZSCurrSubW1 On/Off On
Operation Zero Seq Current
Subtraction Off/On for HV
LocationOLTC1 Winding1 (W1) / Winding2 (W2)
ZSCurrSubW2 On/Off On
TconfigForW1
Operation Zero Seq Current
Subtraction Off/On for LV
Other Parameters -- -
not relevant for this application
use default value
I5/I1 ratio 5-100 25% Fifth to first harmonic ratio
I2/I1 ratio 5 -100 15% Second to first harmonic ratio
Idure 100 - 5000 575% Unrestrained limit
RatedTapOLTC1
HighTapPsOLTC1 --
-- 11 the nominal Tap position
Idmin 10 - 60 30% Maximum Sensitivity
RatedCurrentW1 -- 336 HV rating current
ConnectTypetW1 --
Range Setting Description
-- 115 HV rating voltage
Parameter
- TV side connection type
RatedVoltageW1
QATIF 115/13.8kV
SUBSTATION NO.2 7
RELAY SETTING
Rev.A
8. Doc. No.: EE-221424
Rev. No.: A
2.2 115/13.8KV Transformer LV Restircted Earth Fault Protection Relay Setting
Circuit Ref
:
Relay
Designation
Relay Type Make Areva
Aux.
Voltage
CT Ratio ORDERING NO
Nominal
Current
Freq
CT Data
CT Ratio : Primary 4000 A
: Secondary 1 A
Class TPS
CT Knee Point Voltage (Vkp) 500 V
Magnetising current IM at Vkp 30 mA
CT Secondary resistance RCT 14 Ohms
Max Through fault current
Max Through fault current 25 k A
Relay setting calculations
As per MCAG relay catalogue,
Vs' > If (Rs + Rp)
VsA = VA/Ir + Ir Rsr
Is = Ir + nIe
where,
Vs' = Minimum required stability voltage
If = Maximum sec. through fault current
Rs = CT secondary winding resistance
Rp = maximum loop lead resistance between
CTs and relay
VsA = Actual voltage setting
VA = relay burden
Ir = Relay setting current
Rsr = Resistance of Stabilising series resistor
Is = Effective fault setting expressed in
secondary current
87REF
4000
60HZ
DOCUMENT: RELAY SETTING CALCULATION
MCAG 14
SS DB 0220A
T601 , T602 & T603
125 V DC
1
STATION: QATIF 115/13.8KV SUBSTATION NO.2
QATIF 115/13.8KV
SUBSTATIN NO.2
8
RELAY SETTING
REV.A
9. Doc. No.: EE-221424
Rev. No.: A
DOCUMENT: RELAY SETTING CALCULATION
STATION: QATIF 115/13.8KV SUBSTATION NO.2
Ie = Magnetising current of CT
n = number of CT groups forming the
protected zone.
To determine stability voltage for through fault Vs'
Voltage across the relay at IFS (VS)
CT Resistance (RCT) = 14 Ohms
Lead Loop Resistance (RL) = 0.875 Ohms
Maximum through fault current reflected in CT secondary If = 25x1000x1/4000 = 6.3
VS' = IFS * ( RCT + RL ) = 6.25 X (14+0.875)
92.96875 Volts
Setting voltage 93 V
Setting of the Pickup for the relay, Ir 0.1 A
Rated burden of the relay at relay setting 1 VA
To determine series stabilising resistance Rsr
Stabilising Resistance Rsr = (Vs' - VA/Ir)/Ir (Required) 830.00 ohms
Selected value of stabilising Resistors 1000.00 ohms
Actual Voltage Setting VsA = VA/Ir + Ir*Rsr 93.00 V
the required resistance to the rated value ratio 83.00%
Minimum Fault sensitivity
The offered CT Im 30 mA
Ip T * (Ir + nIm + IM)
Ir 0.10 A
Im at Ual x VsA
Ual
30 x 93 / 500
0.006 A
Total Im for 4 CTs 4 x 0.0056
nIm 0.023 A
IM at Vs 0.52*(sqrt(2)*Vi / C)1/b
C 900
b 0.25
0.52 x (SQRT(2) x 93/ 900)^4
0.00024 A
Ip T * (Ir + nIm + IM)
4000 x (0.1 + 0.023 + 0.00024)
493.0 A
The Sensitivity of the bus bar Protection is 12.32% of CT rating
Im at Vs'
Rsr selection is suitable since its not less
than 65%
QATIF 115/13.8KV
SUBSTATIN NO.2
9
RELAY SETTING
REV.A
10. Doc. No.: EE-221424
Rev. No.: A
PHASE FAULT
2.3 Applicable for -
Relay ordering number = P142316D6M044OJ
System voltage: HV = 115.0 KV
LV = 13.8 KV
CT Ratio = 500 /1 A
Load = 67 MVA
Load Current = 67*1000/(115*sqrt(3)) 336
Tripping co-ordination = 13.8kV Bus Tie O/C Protection
Tripping co-ordination curve = Annexure-B
Overload Factor = 1.20
Relay Pick up Setting Pick up = 1.2*336/500 0.80640 A
Pick up current Chosen = 0.81 In
Required Tripping co-ordination with = T803 MV Directional O/C Relay
T803 MV Directional O/C Relay operating time at fault = 0.35S @ 14520 A
Fault Current on HV Side = 8830*13.8/115 (ETAP Fault File-Annexure B) 1059.60 A
= 0.73S @ 8830A
Required operating time for HV side Directional O/C relay = 0.726 + 0.35 1.08S
fault current on HV Side = 14520 * 13.8/115 = 1742.4
Multiple of fault current w.r.t pickup current = 1059.6/(0.81*500) 2.61630
Relay operating time at TMS = 1 = 0.14 / (2.6162962962963^0.02 - 1) = 7.21 S
Required TMS = 1.076 / 7.20854982736079 = 0.15
TMS Chosen = 0.150
Operating time @ 1.052kA = 0.15*0.14/(2.6162962962963^0.02-1) = 1.081282474
Highset setting = 1.25 times of Maximum through fault current
Maximum through fault current = 1059.00A
= 1.25*1059.6/500 2.649
HS Chosen = 2.65In
Settings for 67MVA Powertransformer HV side Non Directional O/C Relay - 50/51 HV (AREVA P142)
IDMTL Curve = Standard Inverse(IEC)
Relay Pick up Setting = 0.81 In - Setting Range = 0.08 to 4xIn in step of 0.01In
TMS = 0.150 - Setting Range = 0.025 to 1.2 in step of 0.025
HS pick up setting = 2.65In - Setting Range = 0.08 to 32In in step of 0.01In
High Set time delay = 0.050 - Setting Range = 0.00 to 100s in step of 0.01s
115KV POWER TRANSFORMER HV Side NON DIRECTIONAL O/C Relay
(AREVA-P142)
DOCUMENT:
STATION:
RELAY SETTING CALCULATION
QATIF 115/13.8KV SUBSTATION NO. 2
OPERATING TIME OF 13.8KV BUS TIE O/C RELAY FOR FAULT AT
13.8KV BUS
QATIF 115/13.8KV
SUBSTATION NO.2
10
RELAY SETTING
REV.A
11. Doc. No.: EE-221424
Rev. No.: A
PHASE FAULT
2.4 Applicable for -
Relay ordering number = P142316D6M04FOJ
System voltage: = 13.8 KV
CT Ratio = 4000 /1 A
Load = 67 MVA
Load Current = 67*1000/(13.8*sqrt (3)) 2803.00 A
Tripping co-ordination curve = Annexure-B
Grading of Transformer LV Directional relay is such that it should operate before Bus Tie O/C relay for Transformer fault
Recommended Pick up setting = 50% of load current
Relay Pick up Setting Pick up = 0.5*2803/4000 0.35038 A
Pick up current Chosen = 0.36
Maximum 3 phase fault current = 8830 A (ETAP Fault File-Annexure B) 8830.00 A
Bus Tie operating time for this fault current = 0.719S
Required Transformer LV side directional O/C relay operating time = 0.35 s
Multiple of fault current w.r.t pickup current = 8830/(0.36*4000)
= 6.130
Relay operating time at TMS = 1 = 0.14 / (6.13^0.02 - 1) = 3.79 S
Required TMS = 0.35 / 3.79 = 0.09 S
TMS Chosen = 0.100
Operating time @ 8.83 kA = 0.1*0.14/(6.13^0.02-1) = 0.379
Settings for 67MVA Autotransformer MV side Directional O/C Relay - 67 MV (AREVA P142)
IDMTL Curve = Standard Inverse(IEC)
Relay Pick up Setting = 0.36 In - Setting Range = 0.08 to 4xIn in step of 0.01In
TMS = 0.100 - Setting Range = 0.025 to 1.2 in step of 0.025
380KV AUTOTRANSFORMER MV Side DIRECTIONAL O/C Relay (AREVA-
P142)
DOCUMENT: RELAY SETTING CALCULATION
STATION: QATIF 115/13.8KV SUBSTATION NO.2
QATIF 115/13.8KV
SUBSTATION NO.2 11
RELAY SETTING
REV.A
12. Doc. No.: EE-221424
Rev. No.: A
EARTH FAULT
2.5 Applicable for -
Relay ordering number = P142316D6M054OJ
System voltage: HV = 115.0 KV
LV = 13.8 KV
CT Ratio = 500 /1 A
Load = 67 MVA
Load Current = 67*1000/(115*sqrt(3)) 336
Tripping co-ordination = None
Tripping co-ordination curve = Annexure-B
Required Sensitivity = 15% (of CT Rating)
Relay Pick up Setting Pick up = 0.15 In 0.15 In
Pick up current Chosen = 0.15 In
Required Tripping co-ordination with = T803 MV Directional O/C Relay
T803 MV Directional O/C Relay operating time at fault = 0.35S @ 14520 A
Maximum unbalance secondary current = 5 Times of Setting (assumed)
Required operating time = 0.50S 0.50S
fault current on HV Side = 14520 * 13.8/115 = 1742.4
Relay operating time at TMS = 1 = 0.14 / (5^0.02 - 1) = 4.28 S
Required TMS = 0.5 / 4.27972007094537 = 0.117
TMS Chosen = 0.125
Operating time = 0.125*0.14/(5^0.02-1) = 0.534965009
Highest setting = 1.25 times of maximum unbalance secondary current
= 1.25*5*0.15*500/500 0.9375
= 0.94In
Settings for 67MVA Powertransformer HV side Non Directional E/F Relay - 50N/51N (AREVA P142)
IDMTL Curve = Standard Inverse(IEC)
Relay Pick up Setting = 0.15 In - Setting Range = 0.08 to 4xIn in step of 0.01In
TMS = 0.125 - Setting Range = 0.025 to 1.2 in step of 0.025
HS pick up setting = 0.94In - Setting Range = 0.08 to 32In in step of 0.01In
High Set time delay = 0.000 - Setting Range = 0.00 to 100s in step of 0.01s
115/13.8KV TRANSFORMER HV Side DIRECTIONAL E/F Relay (AREVA-
P142)
DOCUMENT:
STATION:
RELAY SETTING CALCULATION
QATIF 115/13.8KV SUBSTATION NO.2
QATIF 115/13.8KV
SUBSTATION NO.2
12
RELAY SETTING
REV.A
13. Doc. No.: EE-221424
Rev. No.: A
EARTH FAULT
2.6 Applicable for -
Relay ordering number = P142316D6M044OJ
System voltage: HV = 115.0 KV
MV = 13.8 KV
CT Ratio = 4000 /1 A
Load = 67 MVA
Load Current = 67*1000/(13.8*sqrt(3)) 2803
Tripping co-ordination = Annexure-B
Tripping co-ordination curve = Annexure-B
Grading of Transformer LV DEF relay is such that it should operate before Bus Tie E/F relay for transformer fault
Relay Pick up Setting Pick up = 0.15 In 0.15 A
Pick up current Chosen = 0.15 In
Required Tripping co-ordination with = T803 MV Directional O/C Relay
T803 MV Directional O/C Relay operating time at fault = 0.35S @ 14520 A
Maximum Through fault current = 9090 A (ETAP Fault File-Annexure B)
13.8kv Bus Tie O/C Relay operating time for this fault current = 0.703 0.703S
Required operating time = 0.35 s
fault current on HV Side = 14520 * 13.8/115 = 1742.4
Multiple of fault current w.r.t pickup current = 9090/(0.15*4000) 15.15000
15.150
Relay operating time at TMS = 1 = 0.14 / (15.15^0.02 - 1) = 2.51 S
Required TMS = 0.35 / 2.50605677006555 = 0.14
TMS Chosen = 0.150
Operating time @ 9.09kA = 0.15*0.14/(19.49^0.02-1) = 0.375908516
Settings for 67MVA Powertransformer MV side Directional E/F Relay - 67 MVN (AREVA P142)
IDMTL Curve = Standard Inverse(IEC)
Relay Pick up Setting = 0.15 In - Setting Range = 0.08 to 4xIn in step of 0.01In
TMS = 0.150 - Setting Range = 0.025 to 1.2 in step of 0.025
67 MVA POWER TRANSFORMER MV Side DIRECTIONAL E/F Relay
(AREVA-P142)
DOCUMENT:
STATION:
RELAY SETTING CALCULATION
QATIF 115/13.8KV SUBSTATIO NO.2
QATIF 115/13.8KV
SUBSTATION NO.2
13
RELAY SETTING
REV.A
14. Doc. No.: EE-221424
Rev. No.: A
EARTH FAULT
2.7 Substation - QATIF 115/13.8KV SUBSTATION NO. 2
Applicable for - 67MVA TRANSFOMER MV GROUND O/C Relay (AREVA-P142)
Relay ordering number = P142316D6M044OJ
System voltage: = 13.8 KV
CT Ratio = 4000 /1A
Load = 67 MVA
Load Current = 67*1000/(13.8*sqrt(3)) = 2803.08 A
Required sensitivity = 40.00% OF CT RATING
Relay Pick up Setting = 0.4*1 = 0.4000 In
Pick up Chosen = 0.400 In Pick up Current Chosen = 0.400 A
Required Co-ordination = 13.8kV Bus Tie E/F Relay
Fault current for co-ordination = 9090 A (ETAP Fault File - Annexure B)
Bus Tie E/F Relay operating time for this fault current = 0.14 x0.25/(11.363^0.02-1) 0.70799784
Required Operating time = 0.35+0.707
= 1.058S
Multiple of fault current w.r.t pick-up current = 9090/(0.4*4000)
= 5.58
Operating time at TMS=1 = 0.14/(5.581^0.02-1)
= 4.00S
Required TMS = 1.05799783966979 /4 = 0.265
TMS Chosen 0.275S
Operating Time @8.93kA = 0.275*0.14/(5.581^0.02-1) = 1.100
Settings for 67MVA TRANSFORMER MV GROUND O/C Relay - 51G (AREVA P142)
IDMTL Curve = Standard Inverse(IEC)
Relay Pick up Setting = 0.40 A - Setting Range = 0.08 to 4xIn in step of 0.01In
TMS = 0.275 - Setting Range = 0.025 to 1.2 in step of 0.025
DOCUMENT: RELAY SETTING CALCULATION
STATION: QATIF 115/13.8KV SUBSTATION NO. 2
QATIF 115/13.8KV
SUBSTATION NO.2 14
RELAY SETTING
REV.A
15. Doc. No.:
Rev. No.:
3.1 115KV BUS COUPLER OVERCURRENT RELAY SETTING
PHASE FAULT
Substation - QATIF 115/13.8KV SUBSTATION NO.2
Applicable for -
Relay Type = P142
Relay Ordering No. = P142316D6M044OJ
System voltage: = 115.0 KV
CT Ratio = 2000 /1 A
Load Current = 808.00 A (ASSUMED)
Over load factor = 1
Tripping co-ordination curve = Annexure-B
Load Current = 808 A
Relay Pick up Setting = 1 X 808/2000 = 0.40400 A
Pick up current Chosen = 0.41
Maximum fault current at 115kV Bus = 24600 A (ETAP Fault File - Annexure B)
Required op. time for this fault current is = 0.50 Sec
Multiple of fault current w.r.t pick-up current = 24600/(0.41x2000)
= 30 Since 30>20
Operating time at TMS =1 = 0.14 /(20^0.02-1) = 2.2674 S
Required TMS = 0.5 /2.26736 = 0.221
TMS Chosen = 0.225
Operating time at selected TMS = 0.14 * TMS / (multiples of optg. Current ^0.02
-1)
= 0.14 * 0.225/ (20^0.02 - 1) = 0.5102 s
Settings for 115kV Bus Coupler O/C Relay - 50/51 (AREVA P142)
IDMTL Curve = Standard Inverse(IEC)
Plug Setting = 0.41 - Setting Range = 0.08 to 4xIn in step of 0.01In
TMS = 0.225 - Setting Range = 0.025 to 1.2 in step of 0.025
DOCUMENT: EE-221424
STATION: A
RELAY SETTING CALCULATION
QATIF 115/13.8KV SUBSTATION NO.2
115KV BUS COUPLER FEEDER OVERCURRENT
RELAY
QATIF 115/13.8KV SUBSTATION NO.2 15
RELAY SETTING
REV.A
16. Doc. No.:
Rev. No.:
3.2 115KV BUS COUPLER E/F OVERCURRENT RELAY SETTING
EARTH FAULT
Substation - QATIF 115/13.8KV SUBSTATION NO.2
Applicable for -
Relay Type = P142
Relay Ordering No. = P142316D6M044OJ
System voltage: = 115.0 KV
CT Ratio = 2000 /1 A
Tripping co-ordination curve = Annexure-B
Relay Pick up Setting = 20% of CT RATING = 0.2In
Pick up current Chosen = 0.2
Maximum 1 Ph earth fault current att 115kV Bus = 19500 A (ETAP Fault File - Annexure B)
Required operating time at 19500 A = 0.4000S
Multiple of fault current w.r.t pick-up current = 19500/(0.2x2000)
= 48.75 Since 48.75 > 20
Operating time at TMS =1 = 0.14 /(20^0.02-1) = 2.2674 S
Required TMS = 0.4 /2.26736 = 0.176
TMS Chosen = 0.175
Operating time at selected TMS = 0.14 * TMS / (multiples of optg. Current ^0.02
-1)
= 0.14 * 0.175/ (20^0.02 - 1) = 0.3968 s
Settings for 115kV Bus Coupler O/C Relay - 50/51 (AREVA P142)
IDMTL Curve = Standard Inverse(IEC)
Plug Setting = 0.2 - Setting Range = 0.08 to 4xIn in step of 0.01In
TMS = 0.175 - Setting Range = 0.025 to 1.2 in step of 0.025
DOCUMENT: EE-221424
STATION: A
RELAY SETTING CALCULATION
QATIF 115/13.8KV SUBSTATION NO.2
115KV BUS COUPLER E/F OVERCURRENT RELAY
QATIF 115/13.8KV SUBSTATION NO.2 16
RELAY SETTING
REV.A
17. Doc. No.:
Rev. No.:
4.1 115KV BUS SECTION OVERCURRENT RELAY SETTING
PHASE FAULT
Substation - QATIF 115/13.8KV SUBSTATION NO.2
Applicable for -
Relay Type = P142
Relay Ordering No. = P142316D6M044OJ
System voltage: = 115.0 KV
CT Ratio = 2000 /1 A
Tripping co-ordination curve = Annexure-B
Load Current = 808 A (assumed)
Overload Factor = 1.0 KV
Relay Pick up Setting = 1 X 808/2000 = 0.40400 A
Pick up current Chosen = 0.41
Max. 3 ph. fault current = 24600 A (ETAP Fault File - Annexure B)
= 0.51 Sec
Required op. time for B/S relay is = 0.51+0.35 0.86016
Multiple of fault current w.r.t pick-up current = 24600/(0.41x2000)
= 30 Since 30 > 20
Operating time at TMS =1 = 0.14 /(20^0.02-1) = 2.2674 S
Required TMS = 0.86016 /2.26736 = 0.379
TMS Chosen = 0.400
Operating time at selected TMS = 0.14 * TMS / (multiples of optg. Current ^0.02
-1)
= 0.14 * 0.4/ (20^0.02 - 1) = 0.8593 s
Settings for 115kV Bus Section O/C Relay - 50/51 (AREVA P142)
IDMTL Curve = Standard Inverse(IEC)
Plug Setting = 0.41 - Setting Range = 0.08 to 4xIn in step of 0.01In
TMS = 0.400 - Setting Range = 0.025 to 1.2 in step of 0.025
115KV BUS SECTION FEEDER OVERCURRENT
RELAY
BUS COUPLER operating time for this fault current
DOCUMENT: EE-221424
STATION: A
RELAY SETTING CALCULATION
QATIF 115/13.8KV SUBSTATION NO.2
QATIF 115/13.8KV SUBSTATION NO.2 17
RELAY SETTING
REV.A
18. Doc. No.:
Rev. No.:
4.2 115KV BUS SECTION E/F OVERCURRENT RELAY SETTING
EARTH FAULT
Substation - QATIF 115/13.8KV SUBSTATION NO.2
Applicable for -
Relay Type = P142
Relay Ordering No. = P142316D6M0440J
System voltage: = 115.0 KV
CT Ratio = 2000 /1 A
Tripping co-ordination curve = Annexure-B
Relay Pick up Setting = 25% of CT RATING = 0.25In
Pick up current Chosen = 0.25
Maximum 1 phase earth fault current at 115 kV Bus = 19500 A (ETAP Fault File - Annexure B)
BUS COUPLER operating time for this fault current = 0.3968S
= 0.396+0.35 0.747
Multiple of fault current w.r.t pick-up current = 19500/(0.25x2000)
= 39 Since 39 > 20
Operating time at TMS =1 = 0.14 /(20^0.02-1) = 2.2674 S
Required TMS = 0.74679 /2.26736 = 0.329
TMS Chosen = 0.350
Operating time at selected TMS = 0.14 * TMS / (multiples of optg. Current ^0.02
-1)
= 0.14 * 0.35/ (20^0.02 - 1) = 0.7936 s
Settings for 115kV Bus Section O/C Relay - 50/51 (AREVA P142)
IDMTL Curve = Standard Inverse(IEC)
Plug Setting = 0.25 - Setting Range = 0.08 to 4xIn in step of 0.01In
TMS = 0.350 - Setting Range = 0.025 to 1.2 in step of 0.025
115KV BUS SECTION E/F OVERCURRENT RELAY
Required Operating time
DOCUMENT: EE-221424
STATION: A
RELAY SETTING CALCULATION
QATIF 115/13.8KV SUBSTATION NO.2
QATIF 115/13.8KV SUBSTATION NO.2 18
RELAY SETTING
REV.A
19. Doc. No.:
Rev. No.:
6.1 13.8KV STATION SERVICE TRANSFORMER FEEDER OVERCURRENT RELAY SETTING
PHASE FAULT
Substation - QATIF 115/13.8KV SUBSTATION NO.2
Applicable for -
Relay Type = REF615
Relay Ordering No. =
System voltage: HV = 13.8 KV
LV = 0.38 KV
CT Ratio = 400 /1 A
Load (Transformer Rating) = 0.5 MVA
Load Current = 21.00 A
Over load factor = 1.2
Tripping co-ordination curve = Annexure-B
Load Current = 21 A
Relay Pick up Setting = 1.2*21/400 = 0.06300 A
Pick up current Chosen = 0.07
Max. 3 ph. fault current at the transformer LV = 14860 A (ETAP Fault File - Annexure B)
Fault current seen by relay transformer HV = (14860*0.38/13.8)
= 409 A
409 A
= 0.35 Sec
Multiple of fault current w.r.t pick-up current = 409/(0.07x400)
= 14.607
Operating time at TMS =1 = 0.14 /(14.607^0.02-1) = 2.5411 S
Required TMS = 0.35 /2.5411 = 0.138
TMS Chosen = 0.150
Operating time at selected TMS = 0.14 * TMS / (multiples of optg. Current ^
0.02
-1)
= 0.14 * 0.15/ (14.607^0.02 - 1) = 0.3812 s
Highset setting = 1.25 times of Maximum through fault current
Maximum through fault current = 409.000 A
= 1.25 * 409/ 400 = 1.28
HS Chosen = 1.28 In
Time delay = 0.05 s
Settings for Station Service Transformer HV side O/C Relay - 50/51 (REF615)
IDMTL Curve = Standard Inverse(IEC)
Plug Setting = 0.07 - Setting Range = 0.05 to 5*In in step of 0.01
TMS = 0.150 - Setting Range = 0.05 to 15 in step of 0.05
HS pick-up setting = 1.280 In - Setting Range = 0.10 to 40xIn in step of 0.01In
Highset time delay = 0.05 - Setting Range = 0.04 to 200s in step of 0.01s
13.8KV STATION SERVICE TRANSFORMER T301 & T302
FEEDER OVERCURRENT RELAY
Required O/C relay Operating time for this fault current
DOCUMENT: EE-221424
STATION: A
RELAY SETTING CALCULATION
QATIF 115/13.8KV SUBSTATION NO.2
QATIF 115/13.8KV
SUBSTATION NO.2 36
RELAY SETTING
REV.A
MVA/R3*KV=500/(1.732*13.8-TRFR primary)
20. Doc. No.:
Rev. No.:
8.2 13.8KV STATION SERVICE TRANSFORMER FEEDER E/F OVERCURRENT RELAY SETTING
EARTH FAULT
Substation - QATIF 115/13.8KV SUBSTATION NO.2
Applicable for -
Relay Type = REF615
Relay Ordering No. =
System voltage: HV = 13.8 KV
CT Ratio = 400 /1 A
Load (Transformer Rating) = 0.5 MVA
Load Current = 21.00 A
Over load factor = 1.2
Load Current = 21 A
Recommended Pick up Setting = 2% of CT rating
Relay Pick up Setting = 0.02 x 1 = 0.02000 A
Pick up current Chosen = 0.05
Max. through fault current = 5 X HV FULL LOAD CURRENT
= 5 X 21 105.00 A
= 0.35 Sec Assumed
Multiple of fault current w.r.t pick-up current = 105/(0.05x400)
= 5.25
Operating time at TMS =1 = 0.14 /(5.25^0.02-1) = 4.1518 S
Required TMS = 0.35 /4.15176 = 0.084
TMS Chosen = 0.100
Operating time at selected TMS = 0.14 * TMS / (multiples of optg. Current ^0.02
-1)
= 0.14 * 0.1/ (5.25^0.02 - 1) = 0.4152 s
Settings for Station Service Transformer HV side E/F O/C Relay - 50N/51N (REF615)
IDMTL Curve = Standard Inverse(IEC)
Plug Setting = 0.05 - Setting Range = 0.05 to 5*In in step of 0.01
TMS = 0.100 - Setting Range = 0.05 to 15 in step of 0.05
13.8KV STATION SERVICE TRANSFORMER T301 &
T302 FEEDER E/F OVERCURRENT RELAY
Required Operating time
DOCUMENT: EE-221424
STATION: A
RELAY SETTING CALCULATION
QATIF 115/13.8KV SUBSTATION NO.2
QATIF 115/13.8KV
SUBSTATION NO.2 37
RELAY SETTING
REV.A
6.2
21. Doc. No.:
Rev. No.:
7.1 13.8KV OUTGOING FEEDER OVERCURRENT RELAY SETTING
PHASE FAULT
Substation - QATIF 115/13.8KV SUBSTATION NO.2
Applicable for -
Relay Type = REF615
Relay Ordering No. =
System voltage: HV = 13.8 KV
CT Ratio = 600 /1 A
Load = 5.0 MVA ASSUMED
Load Current = 209.00 A
Over load factor = 1.2
Tripping co-ordination curve = Annexure-B
Load Current = 209 A
Relay Pick up Setting = 1.2*209/600 = 0.41800 A
Pick up current Chosen = 0.42
Max. 3 ph. fault current at remote end bus = 7870 A (ETAP Fault File - Annexure B)
= 0.35 Sec
Multiple of fault current w.r.t pick-up current = 7870/(0.42x600)
= 31.23 Since 31.032 > 20
Operating time at TMS =1 = 0.14 /(20^0.02-1) = 2.2674 S
Required TMS = 0.35 /2.26736 = 0.154
TMS Chosen = 0.160
Operating time at selected TMS = 0.14 * TMS / (multiples of optg. Current ^
0.02
-1)
= 0.14 * 0.16/ (20^0.02 - 1) = 0.3628 s
Highset setting = 1.25 times of Maximum through fault current
Maximum through fault current = 7870.000 A
= 1.25 * 7870/ 600 = 16.4
HS Chosen = 16.40 In
Time delay = 0.05 s
Settings for OUTGOING FEEDER O/C Relay - 50/51 (REF615)
IDMTL Curve = Standard Inverse(IEC)
Plug Setting = 0.42 - Setting Range = 0.05 to 5*In in step of 0.01
TMS = 0.160 - Setting Range = 0.05 to 15 in step of 0.05
HS pick-up setting = 16.400 In - Setting Range = 0.10 to 40xIn in step of 0.01In
Highset time delay = 0.05 - Setting Range = 0.04 to 200s in step of 0.01s
13.8KV OUTGOING FEEDER OVERCURRENT
RELAY
Required O/C relay Operating time for this fault current
Assuming remote end relay
operates instantaneously
DOCUMENT: EE-221424
STATION: A
RELAY SETTING CALCULATION
QATIF 115/13.8KV SUBSTATION NO.2
QATIF 115/13.8KV
SUBSTATION NO.2 38
RELAY SETTING
REV.A
22. Doc. No.:
Rev. No.:
7.2 13.8KV OUTGOING FEEDER E/F OVERCURRENT RELAY SETTING
EARTH FAULT
Substation - QATIF 115/13.8KV SUBSTATION NO.2
Applicable for -
Relay Type = REF615
Relay Ordering No. =
System voltage: HV = 13.8 KV
CT Ratio = 600 /1 A
Load = 5.0 MVA ASSUMED
Load Current = 209.00 A
Over load factor = 1.2
Load Current = 209 A
Recommended Pick up Setting = 10% of CT rating
Relay Pick up Setting = 0.1 x 1 = 0.10000 A
Pick up current Chosen = 0.1
Max. through fault current = 6290 A
= 0.35 Sec Assumed
Multiple of fault current w.r.t pick-up current = 6290/(0.1x600) 104.83
= 20 SINCE 104.83 > 20
Operating time at TMS =1 = 0.14 /(20^0.02-1) = 2.2674 S
Required TMS = 0.35 /2.26736 = 0.154
TMS Chosen = 0.150
Operating time at selected TMS = 0.14 * TMS / (multiples of optg. Current ^0.02
-1)
= 0.14 * 0.15/ (20^0.02 - 1) = 0.3401 s
HIGHSET SETTING =
MAXIMUM REMOTE END FAULT CURRENT = 6290.0 A
= 1.25*6290/600 13.1042 s
HS CHOSEN = 13.11In
IDMTL Curve = Standard Inverse(IEC)
Plug Setting = 0.1 - Setting Range = 0.05 to 5*In in step of 0.01
TMS = 0.150 - Setting Range = 0.05 to 15 in step of 0.05
HIGHEST SETTING = 13.11In Setting Range = 1 to 40xIn in step of 0.01
= 0.02s Setting Range = 0.02 to 200s in step of 0.01s
13.8KV OUTGOING FEEDER E/F OVERCURRENT
RELAY
Required Operating time
1.2 TIMES OF MAXIMUM REMOTE END FAULT
CURRENT
HIGHEST TIME DELAY
DOCUMENT: EE-221424
STATION: A
RELAY SETTING CALCULATION
QATIF 115/13.8KV SUBSTATION NO.2
Settings for Outgoing Feeder E/F O/C Relay - 50N/51N (REF615)
[ ]
1
c u r r e n t
f a u l t
o f
M u l t i p l e s 0 . 0 2 −
QATIF 115/13.8KV
SUBSTATION NO.2 39
RELAY SETTING
REV.A
23. Doc. No.:
Rev. No.:
8.1 13.8KV BUS SECTION OVERCURRENT RELAY SETTING
PHASE FAULT
Substation - QATIF 115/13.8KV SUBSTATION NO.2
Applicable for -
Relay Type = REF615
Relay Ordering No. =
System voltage: = 13.8 KV
CT Ratio = 4000 /1 A
Load Current = 2803.00 A ASSUMED
Over load factor = 1.1
Tripping co-ordination curve = Annexure-B
Load Current = 2803 A
Relay Pick up Setting = 1.2 X 2803/4000 = 0.84090 A
Pick up current Chosen = 0.85
Max. 3 ph. fault current = 8830 A (ETAP Fault File - Annexure B)
fault current for coordination = 13.8KV OUTGOING FEEDER O/C FAULT CURRENT
=
= 0.36 Sec
Required op. time for B/S relay is = 0.36+0.35 0.72
Multiple of fault current w.r.t pick-up current = 8830/(0.85x4000)
= 2.597
Operating time at TMS =1 = 0.14 /(2.597^0.02-1) = 7.2650 S
Required TMS = 0.7228 /7.265 = 0.099
TMS Chosen = 0.100
Operating time at selected TMS = 0.14 * TMS / (multiples of optg. Current ^0.02
-1)
= 0.14 * 0.1/ (2.597^0.02 - 1) = 0.7192 s
Settings for 13.8kV Bus Section O/C Relay - 50/51 (REF615)
IDMTL Curve = Standard Inverse(IEC)
Plug Setting = 0.85 - Setting Range = 0.05 to 5*In in step of 0.01
TMS = 0.100 - Setting Range = 0.05 to 15 in step of 0.05
DOCUMENT: EE-221424
STATION: A
RELAY SETTING CALCULATION
QATIF 115/13.8KV SUBSTATION NO.2
13.8KV BUS SECTION FEEDER OVERCURRENT
RELAY
IDMT optg time of 13.8kV OUTGOING Feeder O/C relay for this fault
current
QATIF 115/13.8KV SUBSTATION NO.2 40
RELAY SETTING
REV.A
trfr FLC MVA/R3*KV=67000/(1.732*13.8)
24. Doc. No.:
Rev. No.:
8.2 13.8KV BUS SECTION E/F OVERCURRENT RELAY SETTING
EARTH FAULT
Substation - QATIF 115/13.8KV SUBSTATION NO.2
Applicable for -
Relay Type = REF615
Relay Ordering No. =
System voltage: = 13.8 KV
CT Ratio = 4000 /1 A
Load Current = 2803.00 A
Over load factor = 1.1
Tripping Coordination = 13.8kV OUTGOING Feeder O/C E/F Protection.
Tripping co-ordination curve = Annexure-B
Load Current = 2803 A
Relay Pick up Setting = 20 % of CT Sec. rating = 0.20000 A
Pick up current Chosen = 0.2
Max. through fault current = 9090 A (ETAP Fault File - Annexure B)
= 0.3400S
= 0.34+0.35 0.69
Multiple of fault current w.r.t pick-up current = 9090/(0.2x4000)
= 11.363
Operating time at TMS =1 = 0.14 /(11.363^0.02-1) = 2.8108 S
Required TMS = 0.69 /2.8108 = 0.245
TMS Chosen = 0.250
Operating time at selected TMS = 0.14 * TMS / (multiples of optg. Current ^0.02
-1)
= 0.14 *0.25/ (11.363^0.02 - 1) = 0.7027 s
Settings for Bus Section E/F O/C Relay - 50N/51N (REF615)
IDMTL Curve = Standard Inverse(IEC)
Plug Setting = 0.2 - Setting Range = 0.05 to 5*In in step of 0.01
TMS = 0.250 - Setting Range = 0.05 to 15 in step of 0.05
DOCUMENT: EE-221424
STATION: A
RELAY SETTING CALCULATION
QATIF 115/13.8KV SUBSTATION NO.2
13.8KV BUS SECTION A304 E/F OVERCURRENT
RELAY
Required Operating time
IDMT optg time of OUTGOING Feeder E/F O/C relay for this fault
current
QATIF 115/13.8KV SUBSTATION NO.2 41
RELAY SETTING
REV.A
25. Doc. No.:
Rev. No.:
9 13.8KV CAPACITOR BANK RELAY SETTING
9.1 CAPACITOR BANK NEUTRAL UN-BALANCE SETTING
Substation - QATIF 115/13.8KV SUBSTATION NO.2
Applicable for - 13.8kV CAPACITOR BANK
Relay Type = AREVA - MICOM P142
Relay Ordering Data = P142316D6M0440J
System voltage: = 13.8 KV
CT Ratio = 50 /5 A
ALARM STAGE CURRENT SETTING = 2.0 A
ALARM STAGE TIME SETTING = 5 Sec
TRIP STAGE CURRENT SETTING = 4.14 A
TRIP STAGE TIME SETTING = 1.0 Sec
Settings range for 13.8kV capacitor bank neutral un-balance current relay 46-1 & 46-2(Areva - MICOM P142)
SETTING FOR STAGE-1
= 2.00 A
= 5.00 s
SETTING FOR STAGE-2
= 4.14 A
= 1.00S
STARTING CURRENT
OPERATING TIME
STARTING CURRENT
EE-221424
STATION: A
RELAY SETTING CALCULATION
QATIF 115/13.8KV SUBSTATION NO.2
DOCUMENT:
OPERATING TIME
QATIF 115/13.8KV
SUBSTATION NO.2 42
RELAY SETTING
REV.A
26. Doc. No.:
Rev. No.:
9 13.8KV CAPACITOR BANK RELAY SETTING
EE-221424
STATION: A
RELAY SETTING CALCULATION
QATIF 115/13.8KV SUBSTATION NO.2
DOCUMENT:
9.2 13.8kV Capacitor bank inst PH O/C protection (50PA, 50PB & 50PC)
Substation - QATIF 115/13.8KV SUBSTATION NO.2
Applicable for - 13.8kV CAPACITOR BANK
Relay Type = ABB - RXIG22
Relay Ordering Data RK 411 008 DG
System voltage: = 13.8 KV
CT Ratio = 1200-600-400/1A
Adopted Tap 600 /1 A
= 2.03kA
= 2.55kA
Relay setting = 1.2 X outrush Current / (SQRT(2) X CTR)
=1.2 x 2.55X 1000 /( sqrt(2) x600)
= 3.61 A
Relay setting = 4.50 A
Back-Back switching is not consider since this detail is not available
Settings range for 13.8kV capacitor bank instantaneous PH O/C - ABB - RXIG22 (50PA,50PB&50PC)
= 4.50 A
Note : Since the relay operating current increases to +600% for 360HZ this setting will not operate the relay during Inrush
condition.
RELAY SETTING
Maximum peak inrush current
Maximum peak outrush current
QATIF 115/13.8KV
SUBSTATION NO.2 43
RELAY SETTING
REV.A
27. Doc. No.:
Rev. No.:
9 13.8KV CAPACITOR BANK RELAY SETTING
EE-221424
STATION: A
RELAY SETTING CALCULATION
QATIF 115/13.8KV SUBSTATION NO.2
DOCUMENT:
9.3 13.8kV Capacitor bank INST E/F protection-RXIG22 (50PN)
Substation - QATIF 115/13.8KV SUBSTATION NO.2
Applicable for - 13.8kV CAPACITOR BANK
Relay Type = ABB - RXIG22
Relay Ordering Data RK 411 008 DG
System voltage: = 13.8 KV
CT Ratio = 1200-600-400/1A
Adopted Tap 600 /1 A
2030A @ 358 HZ
2550A @ 358 HZ
RELAY SETTING = 2.25A
Back-Back switching is not consider since this detail is not available
Settings range for 13.8kV capacitor bank instantaneous E/F Protection(50PN) - ABB - RXIG22
= 2.25A
RELAY SETTING
Maximum peak inrush current
Maximum peak outrush current
Note : Since the relay operating current increases to +600% for 360HZ this setting will not operate the relay during Inrush
condition.
QATIF 115/13.8KV
SUBSTATION NO.2 44
RELAY SETTING
REV.A
28. Doc. No.:
Rev. No.:
9 13.8KV CAPACITOR BANK RELAY SETTING
EE-221424
STATION: A
RELAY SETTING CALCULATION
QATIF 115/13.8KV SUBSTATION NO.2
DOCUMENT:
9.4 13.8kV Capacitor bank IDMT PH O/C protection
Substation - QATIF 115/13.8KV SUBSTATION NO.2
Applicable for - 13.8kV CAPACITOR BANK
Relay Type = AREVA - P142
Relay Ordering Data P142316D6M0440J
System voltage: = 13.8 KV
CT Ratio = 1200-600-400/1A
Adopted Tap 600 /1 A
Capacitor rating = 7.0 MVar
Capacitor current = = 7x10^3/(sqrt(3) x 13.8) 293.00 A
Relay setting = (1.35Xcapacitor current/CT ratio)
= (1.35X293/600) 0.66 In
Relay IDMTL curve = VERY INVERSE
Fault current considered = 5000A Assumed
Operating time required = 0.5 s Assumed
Fault current in multiples of relay setting = (5000/(0.66X600) 12.63 times
= (13.5/12.63-1) 1.16 S
Required relay operating time = 0.50 s Assumed
Required TMS setting = (0.5/1.16) 0.44
TMS SETTING = 0.45
Settings range for 13.8kV capacitor bank IDMT PH O/C Protection(51P) - AREVA - P142
IDMTL Curve = Very Inverse(IEC)
Plug Setting = 0.66 In - Setting Range = 0.08 to 4A in step 0.01A
TMS = 0.45 - Setting Range = 0.025 to 1.2 in step 0.005
Relay operating time at TMS 1 for 13.66 times the
fault current
QATIF 115/13.8KV
SUBSTATION NO.2 45
RELAY SETTING
REV.A
29. Doc. No.:
Rev. No.:
9 13.8KV CAPACITOR BANK RELAY SETTING
EE-221424
STATION: A
RELAY SETTING CALCULATION
QATIF 115/13.8KV SUBSTATION NO.2
DOCUMENT:
9.5 13.8kV Capacitor bank IDMT E/F protection
Substation - QATIF 115/13.8KV SUBSTATION NO.2
Applicable for - 13.8kV CAPACITOR BANK
Relay Type = AREVA - P142
Relay Ordering Data P142316D6M0440J
System voltage: = 13.8 KV
CT Ratio = 1200-600-400/1A
Adopted Tap 600 /1 A
Capacitor rating = 7000.0 KVar
Capacitor current = 7000/(sqrt(3) x 13.8) 293.00 A
Relay setting = 50% of CT current
= 0.5
Relay IDMTL curve = Normal Inverse
Fault current considered = 5000 A Assumed
Operating time required = 0.25 s Assumed
Fault current in multiples of relay setting = (5000/(0.5X600) 16.67 times
=
= (0.14/16.67^0.02-1) 2.42 S
Required relay operating time = 0.25 s
Required TMS setting = (0.25/2.42) 0.10
TMS SETTING = 0.10
Settings range for 13.8kV capacitor bank IDMT E/F Protection(51N) -AREVA - P142
IDMTL Curve = Normal Inverse(IEC)
Plug Setting = 0.50In - Setting Range = 0.08 to 4A in step 0.01A
TMS = 0.10 - Setting Range = 0.025 to 1.2 in step 0.005
Relay operating time at TMS 1 for 15.63 times the
QATIF 115/13.8KV
SUBSTATION NO.2 46
RELAY SETTING
REV.A
30. Doc. No.:
Rev. No.:
9 13.8KV CAPACITOR BANK RELAY SETTING
EE-221424
STATION: A
RELAY SETTING CALCULATION
QATIF 115/13.8KV SUBSTATION NO.2
DOCUMENT:
9.6 13.8kV Capacitor bank O/V protection 59-1
Substation - QATIF 115/13.8KV SUBSTATION NO.2
Applicable for - 13.8kV CAPACITOR BANK
Relay Type = AREVA P142
Relay Ordering Data P14231AD6M0**0BJ
PT Ratio = 13.8KV/SQRT(3)/115V/SQRT(3))
Overvoltage setting- Alarm = 105% of nominal voltage
= (1.05*66.39) 70.0 V
Time settings = 5.00S
Overvoltage setting- Trip = 110% of nominal voltage
= (1.1x66.39) 73.0 V
Time settings = 3.00 S
Settings range for 13.8kV capacitor bank O/V Protection(59-1) -AREVA P142
starting voltage U> = 70 V
Time seting tU> = 5.00 S
starting voltage U>> = 73 V
Time seting tU>> = 3.00 S
QATIF 115/13.8KV
SUBSTATION NO.2 47
RELAY SETTING
REV.A
31. Doc. No.:
Rev. No.:
9 13.8KV CAPACITOR BANK RELAY SETTING
EE-221424
STATION: A
RELAY SETTING CALCULATION
QATIF 115/13.8KV SUBSTATION NO.2
DOCUMENT:
9.7 13.8kV Capacitor bank O/V protection 59-2
Substation - QATIF 115/13.8KV SUBSTATION NO.2
Applicable for - 13.8kV CAPACITOR BANK
Relay Type = AREVA P142
Relay Ordering Data P14231AD6M0**0BJ
PT Ratio = 13.8KV/SQRT(3)/115V/SQRT(3))
Overvoltage setting- Alarm = 105% of nominal voltage
= (1.05*66.39) 70.0 V
Time settings = 5.00S
Overvoltage setting- Trip = 110% of nominal voltage
= (1.1x66.39) 73.0 V
Time settings = 3.00 S
Settings range for 13.8kV capacitor bank O/V Protection(59-2) -AREVA P142
starting voltage U> = 70 V
Time seting tU> = 5.00 S
starting voltage U>> = 73 V
Time seting tU>> = 3.00 S
QATIF 115/13.8KV
SUBSTATION NO.2 48
RELAY SETTING
REV.A
32. Doc. No.:
Rev. No.:
9 13.8KV CAPACITOR BANK RELAY SETTING
EE-221424
STATION: A
RELAY SETTING CALCULATION
QATIF 115/13.8KV SUBSTATION NO.2
DOCUMENT:
9.8 13.8kV Capacitor bank U/V protection
Substation - QATIF 115/13.8KV SUBSTATION NO.2
Applicable for - 13.8kV CAPACITOR BANK
Relay Type = AREVA P142
Relay Ordering Data P14231AD6M0**0BJ
PT Ratio = 13.8KV/SQRT(3)/115V/SQRT(3))
Under voltage setting = 85% of nominal voltage
= (0.85*66.4) 56.4 V
Time settings = 5.00S
Under voltage setting = 70% of nominal voltage
= (0.7*66.4) 46.5 V
Time settings = 3.00S
Settings range for 13.8kV capacitor bank U/V Protection(27) -AREVA P922
= 56.44 V
= 5.00 S
= 46.48 V
= 3.00 S
Starting voltage 27-1
Time seting t 27-1
Starting voltage 27-2
Time seting 27-2
QATIF 115/13.8KV
SUBSTATION NO.2 49
RELAY SETTING
REV.A
33. Doc. No.: EE-221424
Rev. No.: A
10.1 13.8 KV BB Differential Protection (High Impedence) Relay Setting
Circuit Ref
:
Relay
Designation
Relay Type Make Areva
Aux.
Voltage
CT Ratio ORDERING NO
Nominal
Current
Freq
CT Data
CT Ratio : Primary 4000 A
: Secondary 1 A
Class TPS
CT Knee Point Voltage (Vkp) 500 V
Magnetising current IM at Vkp 30 mA
CT Secondary resistance RCT 14 Ohms
Max Through fault current
Max Through fault current 25 k A
Relay setting calculations
As per MCAG relay catalogue,
Vs' > If (Rs + Rp)
VsA = VA/Ir + Ir Rsr
Is = Ir + nIe
where,
Vs' = Minimum required stability voltage
If = Maximum sec. through fault current
Rs = CT secondary winding resistance
Rp = maximum loop lead resistance between
CTs and relay
VsA = Actual voltage setting
VA = relay burden
Ir = Relay setting current
Rsr = Resistance of Stabilising series resistor
Is = Effective fault setting expressed in
secondary current
DOCUMENT: RELAY SETTING CALCULATION
MCAG 14
13.8KV BUS B1, B2 & B3
125 V DC
1
STATION: QATIF 115/13.8KV SUBSTATION NO.2
87B1-A,
87B1-B,
87B1-C,
87B2-A,
87B2-B,
87B2-C,
87B3-A,
87B3-B,
87B3-C
4000/1A
60HZ
QATIF 115/13.8KV
SUBSTATION NO.2
50
RELAY SETTING
REV.A
34. Doc. No.: EE-221424
Rev. No.: A
DOCUMENT: RELAY SETTING CALCULATION
STATION: QATIF 115/13.8KV SUBSTATION NO.2
Ie = Magnetising current of CT
n = number of CT groups forming the
protected zone.
To determine stability voltage for through fault Vs'
Voltage across the relay at IFS (VS)
CT Resistance (RCT) = 14 Ohms
Lead Loop Resistance (RL) = 1.05 Ohms
Maximum through fault current reflected in CT secondary If = 25x1000x1/4000 = 6.25
VS' = IFS * ( RCT + RL ) = 6.25 X (14+1.05)
94.0625 Volts
Setting voltage 95 V
Setting of the Pickup for the relay, Ir 0.2 A
Rated burden of the realy at relay setting 1 VA
To determine series stabilising resistance Rsr
Stabilising Resistance Rsr = (Vs' - VA/Ir)/Ir (Required) 450.00 ohms
Selected value of stabilising Resistors 450.00 ohms
Actual Voltage Setting VsA = VA/Ir + Ir*Rsr 95.00 V
the required resistance to the rated value ratio 100.00% Rsr selection is suitable since its not less than 65%
Minimum Fault sensitivity
The offered CT Im 30 mA
Ip T * (Ir + nIm + IM)
Ir 0.20 A
Im at Ual x VsA
Ual
30 x 95 / 500
0.00570 A
Total Im for 17 CTs 17 x 0.0057
nIm 0.097 A
IM at Vs 0.52*(sqrt(2)*Vi / C)1/b
C 540
b 0.25
0.52 x (SQRT(2) x 95/ 540)^4
0.00199 A
Ip T * (Ir + nIm + IM)
4000 x (0.2 + 0.0969 + 0.00199)
1195.6 A
The Sensitivity of the bus bar Protection is 29.89% of CT rating
Im at Vs'
QATIF 115/13.8KV
SUBSTATION NO.2
51
RELAY SETTING
REV.A
35. Doc. No.: EE-221424
Rev. No.: A
DOCUMENT: RELAY SETTING CALCULATION
STATION: QATIF 115/13.8KV SUBSTATION NO.2
10.2 13.8 KV BB Differential Protection (High Impedence) CT Supervision Relay
Circuit Ref
:
Relay
Designation
Relay Type Make Areva
Source fault level = 25000 A
Type of protection = CT Secondary Supervision
Type of relay = MVTP
Tr. T601 Ful load current = 2803 A
Sensitivity required = 10% of load current
Sensitivity required = 280.3 A
CT Ratio =
CT secondary resistance Rs = 14 Ohms
Lead resistance (6 sq mm cable) Rp = 1.05 Ohms
=
Voltage developed across the relay
Current reflected in CT secondary = 280.3/(4000/1) A
= 0.0701 A
V = Current x (Rs + Rp + Rsr)
V = 0.07(14+1.05 + 450) V
= 32.588 V
= 33 V
Selected voltage tap in the relay = 2 V
Time setting = 3 s
BUS 1B, 2B & 3B
95B1-A,
95B1-B,
95B1-C,
95B2-A,
95B2-B,
95B2-C,
95B3-A,
95B3-B,
95B3-C
MVTP11
4000/1A
QATIF 115/13.8KV
SUBSTATION NO.2
52
RELAY SETTING
REV.A
36. Doc. No.:
Rev. No.:
11.1 115KV BCU SYNCHROCHECK FUNCTION SETTING
Circuit Ref
:
Relay
Designation
Relay
Type
Make ABB Doc. Ref
Aux.
Voltage
CT Ratio PT Ratio
Nominal
Current
Rated
Voltage
Freq
Synchro Check Relay - REC670 for 115 KV
Substation QATIF 115/13.8KV SUBSTATION NO.2
System voltage: 115 KV
PT sec. Voltage: U1 L-N (line) 115/R3 = 66.4 V
PT sec. Voltage: U2 L-N (Bus) 115/R3 = 66.4 V
System Frequency 60 Hz
Relay Details REC670
SETTINGS
Base Voltage in kV (UBase) 115.0 kV
Voltage Difference limit
Phase shift for Auto & Manual
Frequency diff for Auto & Manual 0.200 HZ
Breaker closing Time 0.080 s
Bus voltage high limit
Line voltage high limit
Time delay output for Synch Auto 0.100 s
Time delay output for Synch Auto 0.100 s
125V
DOCUMENT:
STATION:
15 %UBase
20.00 deg
80 %UBase
80 %UBase
A601, A602, A603,
A604, A605, A606,
A607, A608, A609,
A611, A614, A617
BCU
_
Ur=110V AC
REC 670
EE-221424
A
RELAY SETTING CALCULATION
QATIF 115/13.8KV SUBSTATION NO.2
60HZ
115kV/sqrt3 : 115/sqrt3 -115x 115/sqrt3
- 115V
_
QATIF 115/13.8KV
SUBSTATION NO.2 53
RELAY SETTING
REV.A
37. DOCUMENT: Doc. No EE-221424
STATION: Rev. No. A
12.1 115/13.8KV POWER TRANSFORMER AVR SETTING
Input data
Rating of Power transformer = 67 MVA ONAF
Voltage ratio of Power transformer = 115/13.8 KV
Vector group = Dyn1
% Impedance (HV-LV) = 22.0% @50MVA
Tap range = +12.5% to -20%
Type of relay = MR - TAPCON260
Relay settings
Mode of operation
Local / Remote REMOTE
Auto / Manual Auto
Desired voltage level 115
Bandwidth 0.750%
Delay timer 1 30s
Delay timer 2 5s
Under voltage blocking U< 90%
Over voltage detection U> 110%
Over current blocking I> 77%
Measuring transformer
Voltage transformer 13.8 KV
Current transformer 4000/1A
Phase angle between current path and
voltage path
LDC
Ur 0
Ux 0
Z compensation
Voltage raise 0
Limitation 0
Parallel control
Master / follower Master / follower
CT Parameter
Ratio:
Adopted tap: 4000/1A
Class:
Burden:
TR. parameter
Tr Rating:
Tr % impedance:
Voltage rating
Vector Group
Tap range +12.5% to -20%
VT parameter
Ratio:
67 MVA ONAF
Dyn1
13800/115V
90 Deg
RELAY SETTING CALCULATION
QATIF 115/13.8KV SUBSTATION NO.2
22% @ 50MVA
115/13.8KV
4000-3000-2500-2000-1500-
1000/1A
CL 0.5
30VA
QATIF 115/13.8KV
SUBSTATION NO.2
54
RELAY SETTING
REV.A
58. 67/67N MV T601 - N
OC1 - 67
50/51/50N/51N T302 - G
OC1
50/51/50N/51 N B314 - G
OC1
51G T601 - G
OC1
50/51/50N/51N A304 - G - 51
OC1
50/51/50N/51N T302 - G - LG
50/51/50N/51 N B314 - G - LG
50/51/50N/51N A304 - G - LG
67/67N MV T601 - LG
51G T601 - G - LG
10K
.5 1 10 100 1K
3 5 30 50 300 500 3K 5K
Amps X 10 Bus14 (Nom. kV=13.8, Plot Ref. kV=13.8)
10K
.5 1 10 100 1K
3 5 30 50 300 500 3K 5K
Amps X 10 Bus14 (Nom. kV=13.8, Plot Ref. kV=13.8)
1K
.01
.1
1
10
100
.03
.05
.3
.5
3
5
30
50
300
500
Seconds
1K
.01
.1
1
10
100
.03
.05
.3
.5
3
5
30
50
300
500
Seconds
ETAP Star 11.0.0C
13.8KV EARTH FAULT CURVE
Project:
Location:
Contract:
Engineer:
Filename: E:DG298RELAY SETTINGSREV.0QATIF 2 SSQATIF 2 SS.OTI
Date: 10-23-2013
SN: DAR-ENGING
Rev: Base
Fault: Ground
R 51G T601
R 50/51/50N/51N A304
R 50/51/50N/51 N B314
R 50/51/50N/51N T302
R 67/67N MV T601
67/67N MV T601
50/51/50N/51N A304
50/51/50N/51 N B314
50/51/50N/51N T302
51G T601
59. Seconds
Seconds
R 51/51 N - A601
R 51/51 N A603
51/51 N - A601
51/51 N A603
o
R 50/51/50N/51N-1 T601
R 51G T601
51G T601
T601
67 MVA
T601
67 MVA
50/51/50N/51N-1 T601
60. Seconds
Seconds
R 51/51 N - A601
R 51/51 N A603
51/51 N - A601
51/51 N A603
o
R 50/51/50N/51N-1 T601
T601
67 MVA
T601
67 MVA
50/51/50N/51N-1 T601
61. Location:
Engineer:
Study Case: SC
11.0.0C
Page: 1
SN: DAR-ENGING
Filename: QATIF 2 SS
Project: ETAP
Contract:
Date: 10-23-2013
Revision: Base
Config.: Normal
Electrical Transient Analyzer Program
Short-Circuit Analysis
ANSI Standard
3-Phase, LG, LL, & LLG Fault Currents
30-Cycle Network
Number of Buses:
Number of Branches:
Number of Machines:
24
1
19
0
0
0
1
19
0
0
18
1
0
0
0
4
1
Swing V-Control Total
Load
XFMR2 Total
Tie PD
Impedance
Line/Cable
Reactor
XFMR3
Synchronous
Generator Total
Lumped
Load
Induction
Machines
Synchronous
Motor
Power
Grid
Unit System:
Project Filename:
Output Filename:
System Frequency: 60.00 Hz
English
QATIF 2 SS
E:DG298RELAY SETTINGSREV.0QATIF 2 SSUntitled.SA2
62. Location:
Engineer:
Study Case: SC
11.0.0C
Page: 2
SN: DAR-ENGING
Filename: QATIF 2 SS
Project: ETAP
Contract:
Date: 10-23-2013
Revision: Base
Config.: Normal
Adjustments
Transformer Impedance:
Reactor Impedance:
Tolerance
Overload Heater Resistance:
Transmission Line Length:
Cable Length:
Temperature Correction
Transmission Line Resistance:
Cable Resistance:
Percent
Degree C
Individual
/Global
Individual
/Global
Individual
Individual
Individual
Individual
Apply
Adjustments
Apply
Adjustments
Yes
Yes
No
No
No
Yes
Yes
63. Location:
Engineer:
Study Case: SC
11.0.0C
Page: 3
SN: DAR-ENGING
Filename: QATIF 2 SS
Project: ETAP
Contract:
Date: 10-23-2013
Revision: Base
Config.: Normal
Bus Input Data
ID Type
Bus
Sub-sys
Initial Voltage
%Mag. Ang.
Base kV
Nom. kV
13.800
13.800
Load
Bus1 1 -30.00
100.00
115.000
115.000
Load
Bus1A 1 0.00
100.00
115.000
115.000
Load
Bus1B 1 0.00
100.00
13.800
13.800
Load
Bus2 1 -30.00
100.00
115.000
115.000
Load
Bus2A 1 0.00
100.00
115.000
115.000
Load
Bus2B 1 0.00
100.00
13.800
13.800
Load
Bus3 1 -30.00
100.00
115.000
115.000
SWNG
Bus5 1 0.00
100.00
115.000
115.000
Load
Bus6 1 0.00
100.00
115.000
115.000
Load
Bus7 1 0.00
100.00
115.000
115.000
Load
Bus8 1 0.00
100.00
115.000
115.000
Load
Bus9 1 0.00
100.00
115.000
115.000
Load
Bus11 1 0.00
100.00
115.000
115.000
Load
Bus13 1 0.00
100.00
13.800
13.800
Load
Bus14 1 -30.00
100.00
13.800
13.800
Load
Bus15 1 -30.00
100.00
13.800
13.800
Load
Bus16 1 -30.00
100.00
0.380
0.380
Load
Bus20 1 0.00
100.00
13.800
13.800
Load
Bus21 1 -30.00
100.00
19 Buses Total
All voltages reported by ETAP are in % of bus Nominal kV.
Base kV values of buses are calculated and used internally by ETAP.
64. Location:
Engineer:
Study Case: SC
11.0.0C
Page: 4
SN: DAR-ENGING
Filename: QATIF 2 SS
Project: ETAP
Contract:
Date: 10-23-2013
Revision: Base
Config.: Normal
Line/Cable Input Data
ID Library Size #/Phase T (°C) R1 X1 Y1
Line/Cable
R0 X0 Y0
Ohms or Siemens per 1000 ft per Conductor (Cable) or per Phase (Line)
Adj. (ft) % Tol.
Length
Cable1 15NCUS3 400 16404.2 1 0.0187508 0.0310896 0.0298124 0.0789676
75
0.0
Line / Cable resistances are listed at the specified temperatures.
65. Location:
Engineer:
Study Case: SC
11.0.0C
Page: 5
SN: DAR-ENGING
Filename: QATIF 2 SS
Project: ETAP
Contract:
Date: 10-23-2013
Revision: Base
Config.: Normal
2-Winding Transformer Input Data
Phase Shift
ID MVA Prim. kV Sec. kV % Z X/R Prim. Sec.
Transformer % Tap Setting
% Tol.
Rating Z Variation
+ 5% - 5% Type Angle
% Z
Adjusted
T302 0.500 13.800 0.380 5.00 3.09 0 0
0 0 Dyn -30.000
0 5.0000
T601 67.000 115.000 13.800 29.00 50.40 0 0
0 0 Dyn 30.000
0 29.0000
T602 67.000 115.000 13.800 29.00 50.40 0 0
0 0 Dyn 30.000
0 29.0000
T603 67.000 115.000 13.800 29.00 50.40 0 0
0 0 Dyn 30.000
0 29.0000
2-Winding Transformer Grounding Input Data
ID MVA Prim. kV Sec. kV
Transformer
Type
Rating Primary
Grounding
Conn.
Type
Secondary
Amp Ohm
kV
kV Ohm
Amp
Type
T302 D/Y
0.380
13.800
0.500 Solid
D/Y
13.800
115.000
67.000
T601 Solid
D/Y
13.800
115.000
67.000
T602 Solid
D/Y
13.800
115.000
67.000
T603 Solid
66. Location:
Engineer:
Study Case: SC
11.0.0C
Page: 6
SN: DAR-ENGING
Filename: QATIF 2 SS
Project: ETAP
Contract:
Date: 10-23-2013
Revision: Base
Config.: Normal
Branch Connections
ID From Bus To Bus R X Z
Type
CKT/Branch % Impedance, Pos. Seq., 100 MVAb
Connected Bus ID
Y
T302 Bus2 307.90 951.42 1000.00
Bus20
2W XFMR
T601 Bus9 0.86 43.28 43.28
Bus14
2W XFMR
T602 Bus11 0.86 43.28 43.28
Bus15
2W XFMR
T603 Bus13 0.86 43.28 43.28
Bus16
2W XFMR
Cable1 Bus1 16.15 26.78 31.27
Bus21
Cable
A301 Bus14 Bus1
Tie Breakr
A302 Bus15 Bus2
Tie Breakr
A303 Bus16 Bus3
Tie Breakr
A304 Bus2 Bus1
Tie Breakr
A601 Bus1B Bus1A
Tie Breakr
A602 Bus1B Bus2B
Tie Breakr
A603 Bus1A Bus2A
Tie Breakr
A604 Bus8 Bus13
Tie Breakr
A605 Bus7 Bus11
Tie Breakr
A607 Bus6 Bus9
Tie Breakr
SW1 Bus5 Bus1A
Tie Switch
SW2 Bus5 Bus2A
Tie Switch
SW3 Bus2B Bus2A
Tie Switch
SW4 Bus2A Bus6
Tie Switch
SW5 Bus1A Bus6
Tie Switch
SW6 Bus2A Bus7
Tie Switch
SW7 Bus1A Bus7
Tie Switch
SW8 Bus2B Bus8
Tie Switch
SW9 Bus1B Bus8
Tie Switch
67. Location:
Engineer:
Study Case: SC
11.0.0C
Page: 7
SN: DAR-ENGING
Filename: QATIF 2 SS
Project: ETAP
Contract:
Date: 10-23-2013
Revision: Base
Config.: Normal
Power Grid Input Data
kV X/R R X
Rating 100 MVA Base
MVASC
% Positive Seq. Impedance
ID ID
Power Grid Connected Bus
% Zero Seq. Impedance
X/R R0 X0
100 MVA Base
Grounding
Type
U1 115.000
Bus5 4899.972 0.13055 2.03665
15.60 0.436016 3.61893
8.30
Wye - Solid
Total Power Grids (= 1 ) 4899.972 MVA
68. Location:
Engineer:
Study Case: SC
11.0.0C
Page: 8
SN: DAR-ENGING
Filename: QATIF 2 SS
Project: ETAP
Contract:
Date: 10-23-2013
Revision: Base
Config.: Normal
SHORT- CIRCUIT REPORT
ID Symm. rms
From Bus
ID Va
From Bus To Bus % V kA % Voltage at From Bus
Contribution 3-Phase Fault Looking into "From Bus"
Vb Vc Ia 3I0 R1 X1 R0 X0
kA Symm. rms % Impedance on 100 MVA base
Line-To-Ground Fault
Positive & Zero Sequence Impedances
Fault at bus: Bus1
Prefault voltage = 13.800 kV = 100.00 % of nominal bus kV ( 13.800 kV)
= 100.00 % of base kV ( 13.800 kV)
Bus1 Total 0.00 17.667 0.00 98.66 98.45 18.189 4.29E-001 2.16E+001
18.189 5.60E-001 2.37E+001
Bus21 Bus1 0.00 0.000 0.00 98.66 98.45 0.000 0.000
Bus20 Bus2 0.00 0.000 56.96 100.00 56.84 0.000 0.000
*
Bus11 Bus15 91.39 8.834 95.71 100.00 95.49 9.095 8.59E-001 4.33E+001
9.095 1.12E+000 4.73E+001
*
Bus9 Bus14 91.39 8.834 95.71 100.00 95.49 9.095 8.59E-001 4.33E+001
9.095 1.12E+000 4.73E+001
# Indicates fault current contribution is from three-winding transformers
* Indicates a zero sequence fault current contribution (3I0) from a grounded Delta- Y transformer
69. Location:
Engineer:
Study Case: SC
11.0.0C
Page: 9
SN: DAR-ENGING
Filename: QATIF 2 SS
Project: ETAP
Contract:
Date: 10-23-2013
Revision: Base
Config.: Normal
ID Symm. rms
From Bus
ID Va
From Bus To Bus % V kA % Voltage at From Bus
Contribution 3-Phase Fault Looking into "From Bus"
Vb Vc Ia 3I0 R1 X1 R0 X0
kA Symm. rms % Impedance on 100 MVA base
Line-To-Ground Fault
Positive & Zero Sequence Impedances
Fault at bus: Bus1A
Prefault voltage = 115.000 kV = 100.00 % of nominal bus kV ( 115.000 kV)
= 100.00 % of base kV ( 115.000 kV)
Bus1A Total 0.00 24.600 0.00 110.22 113.46 19.500 4.36E-001 3.62E+000
19.500 1.31E-001 2.04E+000
Bus15 Bus11 0.00 0.000 65.51 63.64 100.00 0.000 0.000
Bus14 Bus9 0.00 0.000 65.51 63.64 100.00 0.000 0.000
U1 Bus5 100.00 24.600 100.00 100.00 100.00 19.500 4.36E-001 3.62E+000
19.500 1.31E-001 2.04E+000
Bus16 Bus13 0.00 0.000 65.51 63.64 100.00 0.000 0.000
# Indicates fault current contribution is from three-winding transformers
* Indicates a zero sequence fault current contribution (3I0) from a grounded Delta- Y transformer
70. Location:
Engineer:
Study Case: SC
11.0.0C
Page: 10
SN: DAR-ENGING
Filename: QATIF 2 SS
Project: ETAP
Contract:
Date: 10-23-2013
Revision: Base
Config.: Normal
ID Symm. rms
From Bus
ID Va
From Bus To Bus % V kA % Voltage at From Bus
Contribution 3-Phase Fault Looking into "From Bus"
Vb Vc Ia 3I0 R1 X1 R0 X0
kA Symm. rms % Impedance on 100 MVA base
Line-To-Ground Fault
Positive & Zero Sequence Impedances
Fault at bus: Bus1B
Prefault voltage = 115.000 kV = 100.00 % of nominal bus kV ( 115.000 kV)
= 100.00 % of base kV ( 115.000 kV)
Bus1B Total 0.00 24.600 0.00 110.22 113.46 19.500 4.36E-001 3.62E+000
19.500 1.31E-001 2.04E+000
Bus16 Bus13 0.00 0.000 65.51 63.64 100.00 0.000 0.000
Bus15 Bus11 0.00 0.000 65.51 63.64 100.00 0.000 0.000
Bus14 Bus9 0.00 0.000 65.51 63.64 100.00 0.000 0.000
U1 Bus5 100.00 24.600 100.00 100.00 100.00 19.500 4.36E-001 3.62E+000
19.500 1.31E-001 2.04E+000
# Indicates fault current contribution is from three-winding transformers
* Indicates a zero sequence fault current contribution (3I0) from a grounded Delta- Y transformer
71. Location:
Engineer:
Study Case: SC
11.0.0C
Page: 11
SN: DAR-ENGING
Filename: QATIF 2 SS
Project: ETAP
Contract:
Date: 10-23-2013
Revision: Base
Config.: Normal
ID Symm. rms
From Bus
ID Va
From Bus To Bus % V kA % Voltage at From Bus
Contribution 3-Phase Fault Looking into "From Bus"
Vb Vc Ia 3I0 R1 X1 R0 X0
kA Symm. rms % Impedance on 100 MVA base
Line-To-Ground Fault
Positive & Zero Sequence Impedances
Fault at bus: Bus2
Prefault voltage = 13.800 kV = 100.00 % of nominal bus kV ( 13.800 kV)
= 100.00 % of base kV ( 13.800 kV)
Bus2 Total 0.00 17.667 0.00 98.66 98.45 18.189 4.29E-001 2.16E+001
18.189 5.60E-001 2.37E+001
Bus20 Bus2 0.00 0.000 56.96 100.00 56.84 0.000 0.000
Bus21 Bus1 0.00 0.000 0.00 98.66 98.45 0.000 0.000
*
Bus9 Bus14 91.39 8.834 95.71 100.00 95.49 9.095 8.59E-001 4.33E+001
9.095 1.12E+000 4.73E+001
*
Bus11 Bus15 91.39 8.834 95.71 100.00 95.49 9.095 8.59E-001 4.33E+001
9.095 1.12E+000 4.73E+001
# Indicates fault current contribution is from three-winding transformers
* Indicates a zero sequence fault current contribution (3I0) from a grounded Delta- Y transformer
72. Location:
Engineer:
Study Case: SC
11.0.0C
Page: 12
SN: DAR-ENGING
Filename: QATIF 2 SS
Project: ETAP
Contract:
Date: 10-23-2013
Revision: Base
Config.: Normal
ID Symm. rms
From Bus
ID Va
From Bus To Bus % V kA % Voltage at From Bus
Contribution 3-Phase Fault Looking into "From Bus"
Vb Vc Ia 3I0 R1 X1 R0 X0
kA Symm. rms % Impedance on 100 MVA base
Line-To-Ground Fault
Positive & Zero Sequence Impedances
Fault at bus: Bus2A
Prefault voltage = 115.000 kV = 100.00 % of nominal bus kV ( 115.000 kV)
= 100.00 % of base kV ( 115.000 kV)
Bus2A Total 0.00 24.600 0.00 110.22 113.46 19.500 4.36E-001 3.62E+000
19.500 1.31E-001 2.04E+000
Bus15 Bus11 0.00 0.000 65.51 63.64 100.00 0.000 0.000
Bus14 Bus9 0.00 0.000 65.51 63.64 100.00 0.000 0.000
Bus16 Bus13 0.00 0.000 65.51 63.64 100.00 0.000 0.000
U1 Bus5 100.00 24.600 100.00 100.00 100.00 19.500 4.36E-001 3.62E+000
19.500 1.31E-001 2.04E+000
# Indicates fault current contribution is from three-winding transformers
* Indicates a zero sequence fault current contribution (3I0) from a grounded Delta- Y transformer
73. Location:
Engineer:
Study Case: SC
11.0.0C
Page: 13
SN: DAR-ENGING
Filename: QATIF 2 SS
Project: ETAP
Contract:
Date: 10-23-2013
Revision: Base
Config.: Normal
ID Symm. rms
From Bus
ID Va
From Bus To Bus % V kA % Voltage at From Bus
Contribution 3-Phase Fault Looking into "From Bus"
Vb Vc Ia 3I0 R1 X1 R0 X0
kA Symm. rms % Impedance on 100 MVA base
Line-To-Ground Fault
Positive & Zero Sequence Impedances
Fault at bus: Bus2B
Prefault voltage = 115.000 kV = 100.00 % of nominal bus kV ( 115.000 kV)
= 100.00 % of base kV ( 115.000 kV)
Bus2B Total 0.00 24.600 0.00 110.22 113.46 19.500 4.36E-001 3.62E+000
19.500 1.31E-001 2.04E+000
Bus16 Bus13 0.00 0.000 65.51 63.64 100.00 0.000 0.000
Bus15 Bus11 0.00 0.000 65.51 63.64 100.00 0.000 0.000
Bus14 Bus9 0.00 0.000 65.51 63.64 100.00 0.000 0.000
U1 Bus5 100.00 24.600 100.00 100.00 100.00 19.500 4.36E-001 3.62E+000
19.500 1.31E-001 2.04E+000
# Indicates fault current contribution is from three-winding transformers
* Indicates a zero sequence fault current contribution (3I0) from a grounded Delta- Y transformer
74. Location:
Engineer:
Study Case: SC
11.0.0C
Page: 14
SN: DAR-ENGING
Filename: QATIF 2 SS
Project: ETAP
Contract:
Date: 10-23-2013
Revision: Base
Config.: Normal
ID Symm. rms
From Bus
ID Va
From Bus To Bus % V kA % Voltage at From Bus
Contribution 3-Phase Fault Looking into "From Bus"
Vb Vc Ia 3I0 R1 X1 R0 X0
kA Symm. rms % Impedance on 100 MVA base
Line-To-Ground Fault
Positive & Zero Sequence Impedances
Fault at bus: Bus3
Prefault voltage = 13.800 kV = 100.00 % of nominal bus kV ( 13.800 kV)
= 100.00 % of base kV ( 13.800 kV)
Bus3 Total 0.00 9.231 0.00 99.30 99.19 9.371 8.59E-001 4.33E+001
9.371 9.89E-001 4.53E+001
*
Bus13 Bus16 95.50 9.231 97.78 100.00 97.67 9.371 8.59E-001 4.33E+001
9.371 9.89E-001 4.53E+001
# Indicates fault current contribution is from three-winding transformers
* Indicates a zero sequence fault current contribution (3I0) from a grounded Delta- Y transformer
75. Location:
Engineer:
Study Case: SC
11.0.0C
Page: 15
SN: DAR-ENGING
Filename: QATIF 2 SS
Project: ETAP
Contract:
Date: 10-23-2013
Revision: Base
Config.: Normal
ID Symm. rms
From Bus
ID Va
From Bus To Bus % V kA % Voltage at From Bus
Contribution 3-Phase Fault Looking into "From Bus"
Vb Vc Ia 3I0 R1 X1 R0 X0
kA Symm. rms % Impedance on 100 MVA base
Line-To-Ground Fault
Positive & Zero Sequence Impedances
Fault at bus: Bus5
Prefault voltage = 115.000 kV = 100.00 % of nominal bus kV ( 115.000 kV)
= 100.00 % of base kV ( 115.000 kV)
Bus5 Total 0.00 24.600 0.00 110.22 113.46 19.500 4.36E-001 3.62E+000
19.500 1.31E-001 2.04E+000
U1 Bus5 100.00 24.600 100.00 100.00 100.00 19.500 4.36E-001 3.62E+000
19.500 1.31E-001 2.04E+000
Bus15 Bus11 0.00 0.000 65.51 63.64 100.00 0.000 0.000
Bus14 Bus9 0.00 0.000 65.51 63.64 100.00 0.000 0.000
Bus16 Bus13 0.00 0.000 65.51 63.64 100.00 0.000 0.000
# Indicates fault current contribution is from three-winding transformers
* Indicates a zero sequence fault current contribution (3I0) from a grounded Delta- Y transformer
76. Location:
Engineer:
Study Case: SC
11.0.0C
Page: 16
SN: DAR-ENGING
Filename: QATIF 2 SS
Project: ETAP
Contract:
Date: 10-23-2013
Revision: Base
Config.: Normal
ID Symm. rms
From Bus
ID Va
From Bus To Bus % V kA % Voltage at From Bus
Contribution 3-Phase Fault Looking into "From Bus"
Vb Vc Ia 3I0 R1 X1 R0 X0
kA Symm. rms % Impedance on 100 MVA base
Line-To-Ground Fault
Positive & Zero Sequence Impedances
Fault at bus: Bus9
Prefault voltage = 115.000 kV = 100.00 % of nominal bus kV ( 115.000 kV)
= 100.00 % of base kV ( 115.000 kV)
Bus9 Total 0.00 24.600 0.00 110.22 113.46 19.500 4.36E-001 3.62E+000
19.500 1.31E-001 2.04E+000
Bus14 Bus9 0.00 0.000 65.51 63.64 100.00 0.000 0.000
Bus15 Bus11 0.00 0.000 65.51 63.64 100.00 0.000 0.000
U1 Bus5 100.00 24.600 100.00 100.00 100.00 19.500 4.36E-001 3.62E+000
19.500 1.31E-001 2.04E+000
Bus16 Bus13 0.00 0.000 65.51 63.64 100.00 0.000 0.000
# Indicates fault current contribution is from three-winding transformers
* Indicates a zero sequence fault current contribution (3I0) from a grounded Delta- Y transformer
77. Location:
Engineer:
Study Case: SC
11.0.0C
Page: 17
SN: DAR-ENGING
Filename: QATIF 2 SS
Project: ETAP
Contract:
Date: 10-23-2013
Revision: Base
Config.: Normal
ID Symm. rms
From Bus
ID Va
From Bus To Bus % V kA % Voltage at From Bus
Contribution 3-Phase Fault Looking into "From Bus"
Vb Vc Ia 3I0 R1 X1 R0 X0
kA Symm. rms % Impedance on 100 MVA base
Line-To-Ground Fault
Positive & Zero Sequence Impedances
Fault at bus: Bus11
Prefault voltage = 115.000 kV = 100.00 % of nominal bus kV ( 115.000 kV)
= 100.00 % of base kV ( 115.000 kV)
Bus11 Total 0.00 24.600 0.00 110.22 113.46 19.500 4.36E-001 3.62E+000
19.500 1.31E-001 2.04E+000
Bus15 Bus11 0.00 0.000 65.51 63.64 100.00 0.000 0.000
Bus14 Bus9 0.00 0.000 65.51 63.64 100.00 0.000 0.000
U1 Bus5 100.00 24.600 100.00 100.00 100.00 19.500 4.36E-001 3.62E+000
19.500 1.31E-001 2.04E+000
Bus16 Bus13 0.00 0.000 65.51 63.64 100.00 0.000 0.000
# Indicates fault current contribution is from three-winding transformers
* Indicates a zero sequence fault current contribution (3I0) from a grounded Delta- Y transformer
78. Location:
Engineer:
Study Case: SC
11.0.0C
Page: 18
SN: DAR-ENGING
Filename: QATIF 2 SS
Project: ETAP
Contract:
Date: 10-23-2013
Revision: Base
Config.: Normal
ID Symm. rms
From Bus
ID Va
From Bus To Bus % V kA % Voltage at From Bus
Contribution 3-Phase Fault Looking into "From Bus"
Vb Vc Ia 3I0 R1 X1 R0 X0
kA Symm. rms % Impedance on 100 MVA base
Line-To-Ground Fault
Positive & Zero Sequence Impedances
Fault at bus: Bus13
Prefault voltage = 115.000 kV = 100.00 % of nominal bus kV ( 115.000 kV)
= 100.00 % of base kV ( 115.000 kV)
Bus13 Total 0.00 24.600 0.00 110.22 113.46 19.500 4.36E-001 3.62E+000
19.500 1.31E-001 2.04E+000
Bus16 Bus13 0.00 0.000 65.51 63.64 100.00 0.000 0.000
Bus15 Bus11 0.00 0.000 65.51 63.64 100.00 0.000 0.000
Bus14 Bus9 0.00 0.000 65.51 63.64 100.00 0.000 0.000
U1 Bus5 100.00 24.600 100.00 100.00 100.00 19.500 4.36E-001 3.62E+000
19.500 1.31E-001 2.04E+000
# Indicates fault current contribution is from three-winding transformers
* Indicates a zero sequence fault current contribution (3I0) from a grounded Delta- Y transformer
79. Location:
Engineer:
Study Case: SC
11.0.0C
Page: 19
SN: DAR-ENGING
Filename: QATIF 2 SS
Project: ETAP
Contract:
Date: 10-23-2013
Revision: Base
Config.: Normal
ID Symm. rms
From Bus
ID Va
From Bus To Bus % V kA % Voltage at From Bus
Contribution 3-Phase Fault Looking into "From Bus"
Vb Vc Ia 3I0 R1 X1 R0 X0
kA Symm. rms % Impedance on 100 MVA base
Line-To-Ground Fault
Positive & Zero Sequence Impedances
Fault at bus: Bus14
Prefault voltage = 13.800 kV = 100.00 % of nominal bus kV ( 13.800 kV)
= 100.00 % of base kV ( 13.800 kV)
Bus14 Total 0.00 17.667 0.00 98.66 98.45 18.189 4.29E-001 2.16E+001
18.189 5.60E-001 2.37E+001
*
Bus9 Bus14 91.39 8.834 95.71 100.00 95.49 9.095 8.59E-001 4.33E+001
9.095 1.12E+000 4.73E+001
Bus21 Bus1 0.00 0.000 0.00 98.66 98.45 0.000 0.000
Bus20 Bus2 0.00 0.000 56.96 100.00 56.84 0.000 0.000
*
Bus11 Bus15 91.39 8.834 95.71 100.00 95.49 9.095 8.59E-001 4.33E+001
9.095 1.12E+000 4.73E+001
# Indicates fault current contribution is from three-winding transformers
* Indicates a zero sequence fault current contribution (3I0) from a grounded Delta- Y transformer
80. Location:
Engineer:
Study Case: SC
11.0.0C
Page: 20
SN: DAR-ENGING
Filename: QATIF 2 SS
Project: ETAP
Contract:
Date: 10-23-2013
Revision: Base
Config.: Normal
ID Symm. rms
From Bus
ID Va
From Bus To Bus % V kA % Voltage at From Bus
Contribution 3-Phase Fault Looking into "From Bus"
Vb Vc Ia 3I0 R1 X1 R0 X0
kA Symm. rms % Impedance on 100 MVA base
Line-To-Ground Fault
Positive & Zero Sequence Impedances
Fault at bus: Bus15
Prefault voltage = 13.800 kV = 100.00 % of nominal bus kV ( 13.800 kV)
= 100.00 % of base kV ( 13.800 kV)
Bus15 Total 0.00 17.667 0.00 98.66 98.45 18.189 4.29E-001 2.16E+001
18.189 5.60E-001 2.37E+001
*
Bus11 Bus15 91.39 8.834 95.71 100.00 95.49 9.095 8.59E-001 4.33E+001
9.095 1.12E+000 4.73E+001
Bus20 Bus2 0.00 0.000 56.96 100.00 56.84 0.000 0.000
Bus21 Bus1 0.00 0.000 0.00 98.66 98.45 0.000 0.000
*
Bus9 Bus14 91.39 8.834 95.71 100.00 95.49 9.095 8.59E-001 4.33E+001
9.095 1.12E+000 4.73E+001
# Indicates fault current contribution is from three-winding transformers
* Indicates a zero sequence fault current contribution (3I0) from a grounded Delta- Y transformer
81. Location:
Engineer:
Study Case: SC
11.0.0C
Page: 21
SN: DAR-ENGING
Filename: QATIF 2 SS
Project: ETAP
Contract:
Date: 10-23-2013
Revision: Base
Config.: Normal
ID Symm. rms
From Bus
ID Va
From Bus To Bus % V kA % Voltage at From Bus
Contribution 3-Phase Fault Looking into "From Bus"
Vb Vc Ia 3I0 R1 X1 R0 X0
kA Symm. rms % Impedance on 100 MVA base
Line-To-Ground Fault
Positive & Zero Sequence Impedances
Fault at bus: Bus16
Prefault voltage = 13.800 kV = 100.00 % of nominal bus kV ( 13.800 kV)
= 100.00 % of base kV ( 13.800 kV)
Bus16 Total 0.00 9.231 0.00 99.30 99.19 9.371 8.59E-001 4.33E+001
9.371 9.89E-001 4.53E+001
*
Bus13 Bus16 95.50 9.231 97.78 100.00 97.67 9.371 8.59E-001 4.33E+001
9.371 9.89E-001 4.53E+001
# Indicates fault current contribution is from three-winding transformers
* Indicates a zero sequence fault current contribution (3I0) from a grounded Delta- Y transformer
82. Location:
Engineer:
Study Case: SC
11.0.0C
Page: 22
SN: DAR-ENGING
Filename: QATIF 2 SS
Project: ETAP
Contract:
Date: 10-23-2013
Revision: Base
Config.: Normal
ID Symm. rms
From Bus
ID Va
From Bus To Bus % V kA % Voltage at From Bus
Contribution 3-Phase Fault Looking into "From Bus"
Vb Vc Ia 3I0 R1 X1 R0 X0
kA Symm. rms % Impedance on 100 MVA base
Line-To-Ground Fault
Positive & Zero Sequence Impedances
Fault at bus: Bus20
Prefault voltage = 0.380 kV = 100.00 % of nominal bus kV ( 0.380 kV)
= 100.00 % of base kV ( 0.380 kV)
Bus20 Total 0.00 14.856 0.00 99.44 99.82 14.967 3.08E+002 9.51E+002
14.967 3.08E+002 9.75E+002
*
Bus2 Bus20 97.78 14.856 99.07 98.69 100.00 14.967 3.08E+002 9.51E+002
14.967 3.08E+002 9.75E+002
# Indicates fault current contribution is from three-winding transformers
* Indicates a zero sequence fault current contribution (3I0) from a grounded Delta- Y transformer
83. Location:
Engineer:
Study Case: SC
11.0.0C
Page: 23
SN: DAR-ENGING
Filename: QATIF 2 SS
Project: ETAP
Contract:
Date: 10-23-2013
Revision: Base
Config.: Normal
ID Symm. rms
From Bus
ID Va
From Bus To Bus % V kA % Voltage at From Bus
Contribution 3-Phase Fault Looking into "From Bus"
Vb Vc Ia 3I0 R1 X1 R0 X0
kA Symm. rms % Impedance on 100 MVA base
Line-To-Ground Fault
Positive & Zero Sequence Impedances
Fault at bus: Bus21
Prefault voltage = 13.800 kV = 100.00 % of nominal bus kV ( 13.800 kV)
= 100.00 % of base kV ( 13.800 kV)
Bus21 Total 0.00 7.872 0.00 112.51 110.39 6.287 2.61E+001 8.97E+001
6.287 1.67E+001 5.05E+001
Bus1 Bus21 58.84 7.872 67.47 99.30 99.72 6.287 2.61E+001 8.97E+001
6.287 1.67E+001 5.05E+001
# Indicates fault current contribution is from three-winding transformers
* Indicates a zero sequence fault current contribution (3I0) from a grounded Delta- Y transformer
96. Date:01/08/2012
(QATIF- EA-221577)
1ZTR121500
N/A
Solidly grounded
N/A
N/A
IEC 60076
35 (yearly average)
55 (max. ambient)
Two
ONAN/ONAF
Dyn1
TRANSMISSION MATERIALS STANDARD SPECIFICATION 53-TMSS-01, Rev. 01
7.0 DATA SCHEDULE
POWER TRANSFORMERS,
RATED 2 MVA UP TO 100 MVA
SEC Enquiry No. Date:
SEC Purchase Order Date:
No.
or Contract No.
SEC PTS No./Project Title with J.O. No. Refer to Main SOW/TS
REFERENCE
SECTION NO. DESCRIPTION 'A' 'B' 'C'
Power Transformer Model No./Type No. *
Type of System Grounding(Solidly
grounded, resistance grounded, other)
HV Effectively Grounded
LV Effectively Grounded
TV (if applicable)
Common Neutral (Auto Transformer)
-
-
3.0 Applicable Industry Standards *
4.0 DESIGN AND CONSTRUCTION REQUIREMENTS
4.1 Design Ambient Temperature (ºC) *
Number of Windings Two
Type of Cooling ON AN /ON AF
Vector Group Designation Dyn1
A'- SEC SPECIFIED DATA/PARAMETER.
'B'- BIDDER/SUPPLIER/VENDOR/CONTRACTOR PROPOSED DATA/PARAMETERS.
'C'- REMARKS SUPPORTING THE PROPOSED DEVIATION IN COLUMN 'B'.
(*) -DATA/PARAMETER TO BE PROVIDED/PROPOSED BY THE BIDDER/SUPPLIER/
VENDOR/CONTRACTOR IN COLUMN 'B'.
53TMSS01R01/AMM Date of Approval: April 02, 2011 PAGE NO. 30 OF 57
97. Date:01/08/2012
50/50/N/A //
67/67/N/A //
N/A/N/A/N/A //
115/13.8/N/A //
50 rise
45 rise
63 rise
N/A
N/A
N/A
22% (50 MVA Base)
N/A
N/A
23.6% (at 50 MVA Base)
N/A
N/A
TRANSMISSION MATERIALS STANDARD SPECIFICATION 53-TMSS-01, Rev. 01
7.0 DATA SCHEDULE
POWER TRANSFORMERS,
RATED 2 MVA UP TO 100 MVA
REFERENCE
SECTION NO. DESCRIPTION 'A' 'B' 'C'
4.2.1 Natural Cooling Rating
HV/LV/TV (MVA) 50 50 ~
1st Stage Forced Cooling
HV/LV/TV (MVA) 6 7 / 6 7/ ~
2nd Stage Forced Cooling
HV/LV/TV (MVA) ~
/ ~
/ ~
Rated Voltage Transformation Ratio
HV/LV/TV (kV) 115 / 13.8/ =
Temperature Rise Based on Ambient
Temperature Conditions Specified in 01-
TMSS-01
Winding °C *
Oil °C *
Winding maximum (hot spot)
Temperature (°C)
*
Design X/R ratio
HV *
LV *
TV *
Impedance Voltage natural cooling power
base and reference temp. of 75°C (%)
(Manufacturer shall indicate the value with
applicable tolerance)
1. At Principal Tap (Guaranteed values) 22%
HV - LV 50MVA Base
HV-TV (if applicable)
LV-TV (if applicable)
*
*
2. At Extreme Plus Tap
HV - LV *
HV-TV (if applicable)
LV-TV (if applicable)
*
*
Date of Approval: April 02, 2011
53TMSS01R01/AMM PAGE NO. 31 OF 57
TRANSMISSION MATERIALS STANDARD SPECIFICATION 53-TMSS-01, Rev. 01
7.0 DATA SCHEDULE
POWER TRANSFORMERS,
RATED 2 MVA UP TO 100 MVA
REFERENCE
SECTION NO. DESCRIPTION 'A' 'B' 'C'
4.2.1 Natural Cooling Rating
HV/LV/TV (MVA) 50 50 ~
1st Stage Forced Cooling
HV/LV/TV (MVA) 6 7 / 6 7/ ~
2nd Stage Forced Cooling
HV/LV/TV (MVA) ~
/ ~
/ ~
Rated Voltage Transformation Ratio
HV/LV/TV (kV) =
Temperature Rise Based on Ambient
Temperature Conditions Specified in 01-
TMSS-01
Winding °C *
Oil °C *
Winding maximum (hot spot)
Temperature (°C)
*
50.4
HV *
LV *
TV *
Impedance Voltage natural cooling power
base and reference temp. of 75°C (%)
(Manufacturer shall indicate the value with
applicable tolerance)
1. At Principal Tap (Guaranteed values) 22%
HV - LV 50MVA Base
HV-TV (if applicable)
LV-TV (if applicable)
*
*
2. At Extreme Plus Tap
HV - LV *
HV-TV (if applicable)
LV-TV (if applicable)
*
*
Date of Approval: April 02, 2011
53TMSS01R01/AMM PAGE NO. 31 OF 57
98. Date:01/08/2012
22.3% (at 50 MVA Base)
N/A
N/A
Approx. 22.2 (at 50 MVA base)
N/A
N/A
Approx. 23.5 (at 50 MVA base)
N/A
N/A
Approx. 22.2 (at 50 MVA base)
N/A
N/A
105
110
1.6
1.76
121%
4.5
4.5
N/A
TRANSMISSION MATERIALS STANDARD SPECIFICATION 53-TMSS-01, Rev. 01
7.0 DATA SCHEDULE
POWER TRANSFORMERS,
RATED 2 MVA UP TO 100 MVA
REFERENCE
SECTION NO. DESCRIPTION 'A' 'B' 'C'
4.2.1 (continued)
3. At Extreme Minus Tap
HV - LV *
HV-TV (if applicable)
LV-TV (if applicable)
*
*
Zero-sequence impedance on natural
cooling power base and reference temp. of
75°C (%)(Manufacturer shall indicate the
value with applicable tolerance)
1. At Principal Tap
HV - LV *
HV-TV (if applicable)
LV-TV (if applicable)
*
*
2. At Extreme Plus Tap
HV - LV *
HV-TV (if applicable)
LV-TV (if applicable)
*
*
3. At Extreme Minus Tap
HV - LV *
HV-TV (if applicable)
LV-TV (if applicable)
*
*
Highest Design Operating Voltage
for the tappings
continuous operation (%)
emergency operation (%)
105
110
Maximum Design Flux Density
at rated voltage (Tesla) *
at 110% rated voltage (Tesla) *
Saturation Voltage (%UN) *
Current density at rated output
Primary winding (Amp/mm2
)
Secondary winding (Amp/mm2
)
Tertiary winding (Amp/mm2
)
*
*
*
No-load current when excited from LV side
as % of full load current
Date of Approval: April 02, 2011
53TMSS01R01/AMM PAGE NO. 32 OF 57
99. Date:01/08/2012
0.10 (Tol=30%)
0.15 (Tol=30%)
0.20 (Tol=30%)
approx.19.9/24.2
-
approx. 13.8/39.9
-
approx.8/23.7
-
-
550
95
N/A
95
N/A
N/A
N/A
N/A
230
38
N/A
38
N/A
N/A
at 100% /110%
-
TRANSMISSION MATERIALS STANDARD SPECIFICATION 53-TMSS-01, Rev. 01
7.0 DATA SCHEDULE
POWER TRANSFORMERS,
RATED 2 MVA UP TO 100 MVA
REFERENCE
SECTION NO. DESCRIPTION 'A' 'B' 'C'
4.2.1 (continued)
100% voltage (Guaranteed value) *
105% voltage *
110% voltage *
No-load current harmonics
at 100% and 110% rated voltage (%)
2nd Harmonics *
3rd Harmonics *
4th Harmonics *
5th Harmonics *
6th Harmonics *
7th Harmonics *
8th Harmonics *
9th Hamonics *
Basic Impulse Withstand Voltage (BIL)
HV winding (kVpeak) *
LV winding (kVpeak) *
HV neutral end (kVpeak) *
LV neutral end (kVpeak) *
Common neutral for auto
transformer winding (kVpeak) *
Tertiary winding (kVpeak) *
Tertiary neutral end (kVpeak) *
(if applicable)
Switching Impulse Withstand Voltage
(BSL) if applicable (kVpeak) *
Separate Source Power Frequency
Withstand Voltage
HV winding (kVrms) *
LV winding (kVrms) *
HV neutral end (kVrms) *
LV neutral end (kVrms) *
Common neutral for auto
transformer winding (kVrms) *
Tertiary Winding (kVrms) *
53TMSS01R01/AMM Date of Approval: April 02, 2011 PAGE NO. 33 OF 57
TRANSMISSION MATERIALS STANDARD SPECIFICATION 53-TMSS-01, Rev. 01
7.0 DATA SCHEDULE
POWER TRANSFORMERS,
RATED 2 MVA UP TO 100 MVA
REFERENCE
SECTION NO. DESCRIPTION 'A' 'B' 'C'
4.2.1 (continued)
100% voltage (Guaranteed value) *
105% voltage *
110% voltage *
No-load current harmonics
at 100% and 110% rated voltage (%)
2nd Harmonics *
3rd Harmonics *
4th Harmonics *
5th Harmonics *
6th Harmonics *
7th Harmonics *
8th Harmonics *
9th Hamonics *
Basic Impulse Withstand Voltage (BIL)
HV winding (kVpeak) *
LV winding (kVpeak) *
HV neutral end (kVpeak) *
LV neutral end (kVpeak) *
Common neutral for auto
transformer winding (kVpeak) *
Tertiary winding (kVpeak) *
Tertiary neutral end (kVpeak) *
(if applicable)
Switching Impulse Withstand Voltage
(BSL) if applicable (kVpeak) *
Separate Source Power Frequency
Withstand Voltage
HV winding (kVrms) *
LV winding (kVrms) *
HV neutral end (kVrms) *
LV neutral end (kVrms) *
Common neutral for auto
transformer winding (kVrms) *
Tertiary Winding (kVrms) *
53TMSS01R01/AMM Date of Approval: April 02, 2011 PAGE NO. 33 OF 57
TRANSMISSION MATERIALS STANDARD SPECIFICATION 53-TMSS-01, Rev. 01
7.0 DATA SCHEDULE
POWER TRANSFORMERS,
RATED 2 MVA UP TO 100 MVA
REFERENCE
SECTION NO. DESCRIPTION 'A' 'B' 'C'
4.2.1 (continued)
100% voltage (Guaranteed value) *
105% voltage *
110% voltage *
No-load current harmonics
at 100% and 110% rated voltage (%)
2nd Harmonics *
3rd Harmonics *
4th Harmonics *
5th Harmonics *
6th Harmonics *
7th Harmonics *
8th Harmonics *
9th Hamonics *
Basic Impulse Withstand Voltage (BIL)
HV winding (kVpeak) *
LV winding (kVpeak) *
HV neutral end (kVpeak) *
LV neutral end (kVpeak) *
Common neutral for auto
transformer winding (kVpeak) *
Tertiary winding (kVpeak) *
Tertiary neutral end (kVpeak) *
(if applicable)
Switching Impulse Withstand Voltage
(BSL) if applicable (kVpeak) *
Separate Source Power Frequency
Withstand Voltage
HV winding (kVrms) *
LV winding (kVrms) *
HV neutral end (kVrms) *
LV neutral end (kVrms) *
Common neutral for auto
transformer winding (kVrms) *
Tertiary Winding (kVrms) *
53TMSS01R01/AMM Date of Approval: April 02, 2011 PAGE NO. 33 OF 57