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Top ten courses on EEP Academy for


Courses and education

Learning and studying have never been easier than nowadays. Since we started the EEP Academy, there are thousands of electrical engineers, students, technicians, and many others who are literally hungry for knowledge and experience. This is where EEP’s contribution comes into the first plan. EEP Academy has over fifty handy and quality electrical engineering courses and bundles.

Top ten courses on EEP Academy for electrical engineers, technicians and students
Top ten courses on EEP Academy for electrical engineers, technicians and students

All video courses at the EEP Academy are pre-recorded and on-demand type. Students have lifetime access to all purchased courses and can access them anytime, there is no time limit.

The instructors are electrical engineers and senior electrical professionals with a minimum level of 10+ years of experience each. Most of them have served at the highest level of various industries throughout the world.

Starting from the fundamentals of electricity and AC/DC circuits, you can learn three-phase power analysis, power transformers, protection & control of high voltage circuits, short-circuit analysis, substation protection, LV distribution design, solar energy systems, electrical designing & drafting, etc. If you are serious about electrical design, you can learn to design electrical systems in the most popular software like Matlab/Simulink, AutoCAD, ETAP, or Dialux.

Whether you are looking to improve your own job or trying to boost your electrical engineering career by expanding your knowledge on the field, the EEP has the most motivating learning paths for you.

If you’re serious about learning and advancing, we recommend taking the EEP Enterprise Membership plan which includes a 50% discount granted on any purchased courses and bundles at EEP Academy. Premium technical articles, guides, and more are included in this plan as well.

More information you can find here.

Please note that courses are not ordered by importance or quality and that the list of the best ones doesn’t end here. There are also many other great courses and bundles worth checking. You can take a look at them all here – Course Catalogue.

Table of Contents:

  1. Ultimate Course To Electrical Design Drawing Using AutoCAD, Dialux And ETAP
  2. Earthing & Grounding in Power Systems – Calculations, Design & Measurements
  3. Low Voltage Distribution Design Course: AutoCAD, DIALux, Excel, Calculations
  4. Electrical Designing and Drafting Course
  5. Distribution Substation and Feeder Protection
  6. Design Tools – Low Voltage Power Calculations in Simaris Design
  7. MATLAB/Simulink Course: Power System Simulations
  8. PLC Programming Course – Fundamentals of PLC Ladder Programming Using Logixpro Simulator
  9. The Substation Fundamentals Course
  10. Power System Analysis – Load Flow and Short Circuits

1. Ultimate Course To Electrical Design Drawing Using AutoCAD, Dialux And ETAP

Course Content – 64 lectures in 8h 5m total length.

Ultimate Course To Electrical Design Drawing Using AutoCAD, Dialux And ETAP
Ultimate Course To Electrical Design Drawing Using AutoCAD, Dialux And ETAP

This course is essential for electrical power engineers who want to work in the distribution field; this will guide you from zero even if you don’t know anything. So what are we going to learn in this course?

  • All necessary tools and commands required by electrical power engineers in AutoCAD.
  • Different types of electrical drawings, various lighting schemes, and lighting situations.
  • Requirements for a good lighting scheme, maintenance, and utilization factors.
  • Lighting design steps (use of catalogs and photometric data in Dialux)
  • How to do the manual calculation for lighting instead of Dialux.
  • Interior design drawing by taking a factory floor and start creating rooms in Dialux.
  • Wiring using AutoCAD and connect the luminaries with Wires and connect to the panel.
  • Adding sockets, do the wiring for them, and connect them to the panel.
  • Electrical panel schedule for our project.
  • Circuit breakers and cables and how to select them for our project.
  • Earthing system and how to design it.
  • Calculation of the voltage drop and short circuit analysis using ETAP.

Who is this course for? – Electrical power engineers who want to learn about interior electrical design.

2. Earthing & Grounding in Power Systems (Design, Calculations, & Measurements)

Course Content – 27 lectures in 4h 36m total length.

Earthing & Grounding in Power Systems (Design, Calculations, & Measurements)
Earthing & Grounding in Power Systems (Design, Calculations, & Measurements)

This course will teach you how to calculate, design, and measure earthing and grounding systems. This course covers all of the earthing issues that you can deal with in real-life applications. You will also learn step potential, touch potential, mesh potential, transfer potential, etc., which are fundamental concepts for designing earthing systems.

General Overview Section – You will learn why we need earthing and grounding systems and the three fundamental grounding systems called TN, TT, and IT.

Measurement Section – You will learn how to measure and calculate soil resistivity with different methods like the variation of depth method, Wenner method, and Schlumberger–Palmer method. You will also learn how to measure earthing resistance with different methods: dead earth method, three-point method, fall of the potential method, and equilateral triangle method.

Design Section – You will learn different earthing topologies that you can use in your projects. A comprehensive example of the earthing system design is also included in the design section.

Calculation Section – You will learn each calculation method for different earthing system topologies like a single earthing rod, single earthing plate, earthing conductor mesh systems without earthing rods, earthing conductor mesh systems with earthing rods, etc.

Who is this course for? – Electrical engineers, technicians, electrical engineering students, anyone who wants to learn electrical power networks.

3. Low Voltage Distribution Design Course: AutoCAD, DIALux, Excel, Calculations

Course Content – 62 lectures in 10h 0m total length.

Low Voltage Distribution Design Course: AutoCAD, DIALux, Excel, Calculations
Low Voltage Distribution Design Course: AutoCAD, DIALux, Excel, Calculations

This course is dedicated to students who are looking to acquire electrical low-voltage power design experience from scratch. It covers low voltage distribution system design-related topics in a total duration of 10 hours.

Essentially, the course begins Section 1 by introducing the well-known drawing software “AutoCAD” by emphasizing its different toolbar options to prepare the student to be familiar with its use. Consequently, lighting design and lux calculations using DIALux software are fully explained in Section 2 to prepare for the lighting distribution system explained and designed as the following step in Section 3.

Thereafter, lighting & power systems distribution is covered in Sections 3 & 4, which in turn prepares the student to understand how to gather information and calculate the total connected loads by the lighting and power designed layouts to be reflected in the panel schedules and single line diagrams which will be explained in the 5th section of this course.

Once reaching this stage of the course, you will have to perform a range of low voltage system-related calculations of sizing Transformers, Generators, Cables, Circuit Breakers, calculations of voltage drop and short circuit current levels, and power factor correction to ensure a safe design for the entire system for the aim of reflecting the calculated values in the single-line diagram of the project.

All these calculations will be explained separately in detail using simple steps that you will be able to apply manually and with the help of predefined Excel sheets for solving different formulas in Section 6.

The last section of this course covers the earthing and lightning system topics emphasizing their different types, components, and the appropriate methods to design these systems according to international standards.

Besides, the course is enhanced with a variety of helpful resources that are attached with it (XLSX, DOC, DWG, and PDF).

Who is this course for? – Electrical engineers, electrical draughtsmen, electrical designers, electrical fresh graduates and technicians.

4. Electrical Designing and Drafting Course (Bundle – 2 Courses)

Course Content – 136 lectures in 13h 51m total length.

Electrical Designing and Drafting Course (Bundle - 2 Courses)
Electrical Designing and Drafting Course (Bundle – 2 Courses)

This course introduces the student to the process of designing residential and commercial projects. After completing this course, you will have high confidence in your practical work and start working on your design projects using AutoCAD. Or if you are fresher, you can start your career as a professional in this competitive world.

Students will learn various electrical calculations and have an access to the comprehensive chapter for learning AutoCAD from scratch to professional level (60 lessons + real project included in DWG). All calculations and explanations are as per the NEC and other international codes and standards.

  • Basics of electrical: The basics of electrical engineering, basic formulae, types of load, operating voltage levels, etc.
  • Basic formulae: Some most important formulae plus a short assignment for you.
  • Codes, Standards & Lux Levels: Internationally acceptable codes & standards, lux level required for any area for lighting design.
  • Illumination Design: Types of lighting lamps, types of the lighting system, Kelvin Color Temp., CRI.
  • Basics of Air Conditioner: For small projects, you will learn the basics of A/C.
  • Circuit Breakers: What is CB, types of CB, working & operation, calculation, etc.
  • Capacitor Banks: The need for a capacitor bank, the benefits, and how to calculate the size of the capacitor bank.
  • Electrical Designing: Calculation of lighting/raw power socket, fans, no. of lighting fixtures, sizing of A/C, load scheduling/balancing, distribution board, etc.
  • Electrical Motors: Types of motor and their application, starting methods, starting current, etc.
  • Electrical Transformer: Transformer parts, classification, cooling methods, winding insulation class, faults, size calculation, etc.
  • Diesel Generator: DG parts of DG, ATS, transformer classification, DG faults, size calculation, etc.
  • UPS: Introduction, types, size calculation, battery size calculation.
  • Cables & Cable Sizing: Introduction, cable sizes, cable parts, insulation types, important points related to cable, size calculation, etc.
  • Voltage Drop Calculation: Voltage Drop Calculation in a cable.
  • Short-Circuit Calculation: Short circuit current capacity calculation for proposed cables, calculate the tripping time of CB.
  • Cable Tray Size Calculation: The concept of cable tray, cable tray size calculation.
  • Earthing: Earthing concept and calculation of earthing pit, strip, rod, etc.

AutoCAD (60 Lessons) – This section relates to the software part, where this AutoCAD chapter you will learn how to use AutoCAD in a professional manner, control keys, function keys, basic drawing commands, modifying commands, editing commands, dimension commands, block/layer, print commands, etc, plus practice.

Assignment At the end, you have given a Real-Time Project for ground + five floors. You have to do all the calculations for a complete electrical design for this building.

Who is this course for? – Electrical graduates, electrical designers, freshers, electrical operators, developers, site engineers, facility maintenance personel, and technicians.

5. Distribution Substation and Feeder Protection Course

Course Content – 5 chapters in 3h 51 min total length.

Distribution Substation and Feeder Protection Course
Distribution Substation and Feeder Protection Course

This course covers utility distribution stations and feeder protection including fuses, new intelligent electronic device (IED) relays, and old-school time overcurrent relays. Feeder relays and apparatus are examined including reclosers.

Power transformer protection is reviewed including current mismatch caused by differing CT ratios; delta-wye transformation & currents shifts; mismatch induced by load tap-changers; CT saturation and remanence, inrush phenomena, and harmonic content problems.

  • Chapter 1 – Per Phase Analysis
  • Chapter 2 – Substation Protection
  • Chapter 3 – A Protection Coordination Problem
  • Chapter 4 – Surge Protective Equipment
  • Chapter 5 – Transformer Protection
  • The Final Exam With 17 Questions

Who is this course for? – Engineers, technologists, technicians, supervisors and students.

6. Design Tools – Low Voltage Power Calculations in Simaris Design

Course Content – 12 lectures in 1h 25m total length

Design Tools - Low Voltage Power Calculations in Simaris Design
Design Tools – Low Voltage Power Calculations in Simaris Design

Planning an automation project and the electrical wiring on that project starts with power calculations. This is one of the first steps you should take when you start working on a new low voltage electrical system.

Simaris Design is, according to our experience, by far the best one out there to quickly set up a project, create single line diagrams, and output all the possible documents that one needs when performing power calculations (project documentation, different list in Excel, e.g. busbar, cable, device settings, selectivity documentation, etc., single line diagrams in PDF and DWG/DXF).

When creating single line diagrams in Simaris Design the devices you use are grouped into three categories:

1. System infeed – Transformer with primary and secondary side, transformer only with secondary side, coupling to use when you have also emergency power supply, like a diesel aggregate (generator), etc.

2. Distribution boards – With busbars, without busbar, sub-distribution boards, etc.

3. Final circuits – Electrical consumers ranging from general devices, motors (including DOL, soft starter, reverse-duty, and frequency converter), power outlets up to special dummy loads. You even have the possibility to insert a charging unit for electric cars. Talking about awesomeness 🙂

We definitely highly recommend this software to all of you who work in the electrical engineering field. We recommend you invest some time to get to know this program. It’s worth it.

Who is this course for? – students of electrical engineering, electricians, engineers, technicians, maintenance department in factories when planning new investments in production, construction site engineers to quickly plan and dimension their low voltage installation, engineering offices when designing new electrical and automation systems, and anyone who needs occasional dimensioning of their low voltage installations.

7. MATLAB/Simulink Course: Power System Simulations

Course Content – 18 lectures in 4h 32m total length.

MATLAB/Simulink Course: Power System Simulations
MATLAB/Simulink Course: Power System Simulations

This course is designed to allow you to simulate power systems in MATLAB/Simulink. This course not only gives a review of the theory of how power systems operate but also gives several examples of how to run different types of power system studies using MATLAB/Simulink. The course is divided into the following sections:

1. Introduction to MATLAB/Simulink for Power Systems:
In the first section of the course, we will begin by reviewing the libraries available in Simulink to represent generators, transformers, transmission lines, and loads in our models. After that, we will take a look at how we can model these components in Simulink, as well as how we can put them together in a model and how we can take measurements in the model to ensure proper simulation.

2. Power System Studies in MATLAB/Simulink:
After we’ve made ourselves familiar with the MATLAB/Simulink environment building a small power system model, we will move on to build a large power system model which includes several generators, transformers, transmission lines, loads, and capacitor banks. We will also model the turbine control systems and excitation control systems for all generators to simulate the realistic dynamic behavior of power systems in real life.

After we have built the entire model, we will run several types of studies, including load flow, short circuit, and stability studies, to simulate the behavior of the system under several conditions. This will give us all the tools we need to build any type of power system and run any power system study using MATLAB/Simulink.

In each section, we will go over several models to illustrate how we can design and simulate power systems in MATLAB/Simulink. The models are also available for download so that you can follow along, as well as use these models and modify them to create your own power system models.

Who is this course for? – Engineering students, practicing engineers, and anybody with an interest in learning about power systems and/or MATLAB/Simulink.

8. PLC Programming Course – Fundamentals of PLC Ladder Programming Using Logixpro Simulator

Course Content – 32 lectures in 6h 30m total length.

PLC Programming Course - Fundamentals of PLC Ladder Programming Using Logixpro Simulator
PLC Programming Course – Fundamentals of PLC Ladder Programming Using Logixpro Simulator

This course is designed for anyone who has zero knowledge about PLC and would like to learn the basics of PLC and ladder programming. In this course, we will use Logixpro Simulator in which we will write the coding and simulate inside the program so that we can see the effect of our ladder diagram.

In this course you will:

  • Understand PLC hardware configuration,
  • Understand the types of inputs and outputs in PLC,
  • Understand the advantages of using PLC over classic control,
  • Differentiate between PLC programming languages,
  • Learn the definition of the PLC scan cycle,
  • How to use markers in PLC,
  • How to use counters and timers,
  • Do tasks in silo, batch, I/O, and door simulators.

Who is this course for? – Anyone who would like to gain knowledge about ladder programming in PLC and engineers who wants to learn about Logixpro Simulator.

9. The Substation Fundamentals Course

Course Content – 29 lectures in 5h 01m total length

The Substation Fundamentals Course
The Substation Fundamentals Course

Course for power engineering students about substations and electric power systems (circuit breakers, grounding systems, ring main units, transmission lines, and more!).

This 5-hour course will discuss the following topics related to electrical power substations:

  • Function, classification, and voltage of electrical substations.
  • Main components like power transformers, conductors, insulators, switch gears, current transformer, capacitor voltage transformer, and voltage transformer.
  • Different types of circuit breakers, relays, their classification according to time, construction, and function.
  • Difference between circuit breaker and fuse and their applications.
  • IP or ingress protection.
  • Grounding system including the effect of current on the human body and components of the grounding system.
  • Types of electric hazards and classification of earthing systems.
  • Measuring the earthing resistance by Megger and the three-point method.
  • Design of an earthing system using ETAP program.
  • Ring main unit and its importance in electrical power system.
  • Types of switches used in electrical power systems and substations.
  • Overhead transmission lines, underground cables, and the difference between them.
  • Busbars in power system, its importance, its different schemes and how to select them.
  • Lightning arrester and wave trap used in substations.
  • Air and gas-insulated substations.
  • Overview of the design of an electrical substation and single line diagram of 66/11 kV substation.

Who is this course for? – Electrical power engineers who want to learn about electrical engineering power systems and substations.

10. Power System Analysis Course: Load Flow and Short Circuits

Course Content – 19 lectures in 3h 27m total length.

Power System Analysis Course: Load Flow and Short Circuits
Power System Analysis Course: Load Flow and Short Circuits

This course is dedicated to one of the main areas of electrical engineering: power system analysis. Power system analysis is the core of power engineering and its understanding is therefore essential for a career in this field. In this course, you will learn about power flow (load flow) analysis and short circuit analysis and their use in power systems.

The course is divided into the following sections:

1. Power Flow (Load Flow) Analysis:
In section 1, we will introduce the concept of power flow. Also referred to as load flow, power flow is the analysis of how apparent, real, and reactive power flows between parts of a power system, from generation to loads. Two different methods will be covered, which are the most widely used methods in power system analysis: the Gauss-Seidel method and the Newton-Raphson method.

Several examples will be solved to help explain how these methods are used for power flow analysis.

2. Short Circuit Analysis of Balanced Faults:
In section 2, we will introduce short circuits. Also referred to as faults, short circuits are undesired occurrences in power systems when conductors are shorted between each other, to ground, or a combination of these.

This is the basis for the field of protection and control which is widely important for the safe and reliable operation of power systems. To introduce how short circuits (faults) affect power systems, we will begin by discussing balanced (i.e., three-phase) short circuits. We will also introduce the concept of the short circuit capacity and the bus impedance matrix.

3. Short Circuit Analysis of Unbalanced Faults:
In section 3, we will continue discussing short circuits (faults) but will discuss the more complex analysis of unbalanced faults (e.g., single-line-to-ground, line-to-line, and line-to-line-to-ground faults). To do this, we will introduce the technique of symmetrical components, which allows us to analyze unbalanced power systems more easily.

In each section, several examples are solved to illustrate how to analyze real-world power systems.

By learning about power flow analysis and short circuit analysis and how they are used in power systems, you will be able to continue your study of power system analysis for a career in power engineering and electrical engineering.

Who is this course for? – Electrical designers, power engineers, and anybody with an interest in learning about power systems and power engineering.



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A few practical ways to determine required


Power triangle & power factor

This article will shed some light on how adding capacitors gives the distribution system the necessary reactive power to return the power factor to the required level. Capacitors act as a source of reactive energy, which accordingly reduces the reactive power that the energy source must supply. The power factor of the system is therefore improved.

Practical ways to determine required reactive energy compensation for a power distribution system
Practical ways to determine required reactive energy compensation for a power distribution system

In an installation consuming reactive power Q1 (Diagram 1), adding a capacitor bank generating a reactive compensation power Qc (Diagram 2) improves the overall efficiency of the installation. The reactive power Q1 initially supplied by the source is reduced to a new Q2 value (Diagram 3), the φ angle is smaller and the cosine of this angle is improved (moves towards 1).

The current consumption is also reduced.

Figure 1 – Power triangle

Power triangle
Figure 1 – Power triangle

Power compensation enables the interests of the user and those of the energy distribution company to be combined, by improving the efficiency of installations through better use of the available power by limiting the consumption of reactive energy that is not only unnecessary and expensive but also a source of overcurrents in conductors.

The example below shows how, by “increasing” the power factor from 0.7 to 0.95, for the same active power of 100 kW, the apparent power S (in VA), in comparison to that which actually has to be supplied has been reduced by 35%.

Figure 2 – An example of increasing the power factor from 0.7 to 0.95

This example shows how, by “increasing” the power factor from 0.7 to 0.95, for the same active power of 100 kW, the apparent power S (in Va), in comparison to that which actually has to be supplied, has been reduced by 35%.
Figure 2 – This example shows how, by “increasing” the power factor from 0.7 to 0.95, for the same active power of 100 kW, the apparent power S (in Va), in
comparison to that which actually has to be supplied has been reduced by 35%.

Power factor calculations:

  • Before PF = 100/142 = 0.70 or 70%
  • After PF = 100/105 = 0.95 or 95%

When the cos changes from an initial value cos φ1 to a final value cos φ2, as a general rule, the ohmic losses are reduced by: (1 – (cos φ1/cos φ2)²) × 100 as a %

Thus changing from a cosφ of 0.7 to 0.95 reduces the losses by 45%. A poor cosφ, therefore, causes voltage drops in the conductors. The voltage drop in an electric line can be calculated using the formula: ΔU = I ( R cosφ + L sinφ). The maximum power that can be transmitted in an AC system is calculated using the following formulae:

P = U I cosφ for single-phase and P = U I √3 cosφ for three-phase.

For the same current, the power transmitted is in direct proportion to the cos φ. Thus changing from a cos φ of 0.7 to 0.95 enables the active power (in W) to be increased by 35% while reducing the associated line heat losses and voltage drops (see above). The power that a transformer can deliver is expressed in kVA. This is the available apparent power. Even better use will be made of this transformer if the cos φ of the load is close to 1.

Improving the cos φ from an initial value cos φ1 to a final value cos φ2, for X (W) power used, releases an additional usable apparent power of S (kVa) = p(kW) × ((1/cos φ1) – (1/cos φ2)). Therefore a 1000 kVa transformer delivering a load of 700 kW with a cosφ of 0.7 is at its maximum load.

By improving the cos φ from 0.7 to 0.95, an additional available active power of 250 kW is released.

Table of Contents:

  1. Determining the compensation by theoretical calculation
    1. Based on the cosφ and the currents
    2. Based on tanφ and powers
    3. Over-compensation
  2. Determining the compensation based on the billing information
    1. With reactive energy metering
    2. Without reactive energy metering
    3. Example of potential savings on an installation billed in kVA
  3. Calculation based on measured elements
    1. Power measurement
    2. Calculation for energy suppliers (small power plants)
  4. Conversion table

1. Determining the compensation by theoretical calculation

1.1. Based on the cosϕ and the currents

Figure 3 – Determining compensation based on the cosϕ and the currents

Determining compensation based on the cosϕ and the currents
Figure 3 – Determining compensation based on the cosϕ and the currents

Where:

  • Ia – active current
  • Iti – initial apparent current (before correction)
  • Itf – final apparent current (after correction)
  • φi – phase shift before the correction
  • φf – phase shift after correction
  • Iri – reactive current before the correction
  • Irf – reactive current after correction
  • Ia = Iti cos φi = Itf cos φf

The final current is reduced so that: Itf = Iti cosφi/cosφf

The reduction of the apparent current is proportional to the improvement of the cosφ for the same active power P = UI cosφ. Likewise, compensation of the cosφ, at constant apparent current, will enable an active power (Pf) increased in the same proportion as the ratio between the initial cos ϕ and the corrected cosφ to be carried.

Pf/Pi = cosφf / cosφi

The reactive power compensation Qc can be defined as being the difference between the initial power (Qi = U×Irf×sinφi) and the reactive power obtained after
compensation (Qf = U×Irf×sinφf):

Qc = U × (Iri – Irf)·(sinφi – sinφf)

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1.2. Based on tanφ and powers

Calculation based on the powers enables the required tan value to be used directly to determine the reactive power compensation to be installed.

Figure 4 – Determining compensation based on the tan ϕ and powers

Determining compensation based on the tan ϕ and powers
Figure 4 – Determining compensation based on the tan ϕ and powers

  • Initial value of tan φi = Q/P
  • Required value of tan φf = Q’/P
  • Qc = Q – Q’ i.e. Qc = P (tan φi – tan φf)

The power compensation is very easy to calculate from the required tan value. The capacitance value in farads is calculated as follows:

C = P (tan φi – tan φf) / ωU2

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1.3 Over-compensation

When the power compensation (Qc1) is determined correctly, its value must be as close as possible to the reactive power Q to be compensated and the phase shift angle (ϕ’) tends towards 0. If the compensation (Qc2) is greater than the reactive power, the phase-shift angle (φ”) increases, and the apparent power S” increases.

The circuit becomes predominantly capacitive. This leads to an increase in the current consumed which defeats the purpose.

Figure 5 – Over-compensation

Over-compensation
Figure 5 – Over-compensation

Over-compensation also tends to increase the voltage applied to the installation. It must be avoided. It is generally considered that it should not exceed 1.15 times the power to be compensated. The use of power factor controllers and step capacitor banks avoids problems of overcompensation.

Figure 6 – Over-compensation currents

Increasing the voltage applied to the installation
Figure 6 – Increasing the voltage applied to the installation

Over-compensation (Ic >Ir), increases the apparent current consumed and also increases the voltage applied to the equipment. The illustration of vectors V2S (with over-compensation) and V2 (with appropriate compensation) shows this phenomenon, which must be avoided.

Care must be taken when choosing energy compensation.

Go back to Contents Table ↑

2. Determining the compensation based on the billing information

As pricing and metering methods can vary from country to country, only a general process for assessing the need for reactive compensation, using the energy distribution company’s readings or bills, will be described here. Depending on the pricing method, access to the reactive energy consumption (kvarh) may be direct, together with the number of hours to which this value refers. it is then billed proportionately.

This is generally the case for high power connections with one or more MV/LV transformers dedicated to the installation.

For lower power connections, the reactive power consumption may be indirectly billed by the overconsumption of the apparent power (in VA) that is causes. For a “monitored power” connection, it is then billed according to the amounts by which the subscribed nominal apparent power is exceeded.

Go back to Contents Table ↑

2.1. With reactive energy metering

In general, billing is applied when the tanφ exceeds a certain value (0.4 for example) and also according to time periods (peak times) or seasons (winter). The following calculation method, given for information purposes only, can be used to calculate the capacitor banks to be installed at the supply end of an installation with the regular, repetitive operation.

For random or sequenced operation, automatic banks, which switch on according to the load, are recommended so as not to “overcompensate” the installation.

  • Analyze the bills for the period for which the reactive power is charged
  • Select the month in which the bill is highest (kvarh to be billed)
  • Evaluate the number of hours the installation operates per month (NBhm) (for example high-load times and peak times) during which the reactive energy is billed.

The amount of reactive energy billed Erfac will be: Erfac = Er – Ea×tanφ = Er – (0.4×Ea)

Power Qc of the capacitors to be installed: Qc = Er/NBhm

  • Erfac – Reactive energy billed each month (in kvarh)
  • Ea (kWh) – Monthly active energy consumption for the period and the times defined above
  • Er (kvarh) – Reactive energy consumption for the same period
  • NBhm – Number of hours operation per month for which Er is billed

Depending on the metering and billing methods, a certain amount of reactive energy may be permitted free or at a discounted rate by the distribution company. In the same way, if metering is carried out at low voltage, the share of the reactive power consumed by the MV/LV transformer is added to the billed energy on a fixed basis.

For example, if the permitted value of tanφ changes to 0.31, the amount of reactive energy billed Erfac will become:

Erfac = Er – Ea×tanφ = Er – (0.31×Ea)

Figure 7 – Multifunction digital measurement control unit with reactive energy metering

Multifunction digital measurement control unit with reactive energy metering
Figure 7 – Multifunction digital measurement control unit with reactive energy metering (photo credit: zillionelectric.com)

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2.2. Without reactive energy metering

In this type of supply contract (for example, “yellow tariff” – low power supply – in France), the reactive energy consumption is not shown on the electricity bill. It is charged indirectly, based on the consumption of apparent power in kVA. The distribution company charges a “fixed charge” that depends on the subscribed apparent power. Above this power, the consumer pays penalties. this is the principle of “monitored power”.

Reactive energy compensation reduces the fixed charge by reducing the subscribed apparent power. It also enables the amounts over and above this subscribed demand to be limited (billing of the additional kVA over the limit).

To determine the reactive power value to be installed, the capital investment costs of the capacitors must be compared with the savings on the fixed charge paid to the distribution company.

In practice, it is extremely inadvisable to install a capacitor bank without an accurate power analysis (calculated or simulated using software) or without preliminary measurements. Under-compensation will not provide the expected saving on the power consumption, while over-compensation will lead to probable overvoltages and resonance in relation to the supply. Remember that there is an increased risk of malfunctions in low-power installations or those with distorting loads (harmonics).

Nowadays reactive power is only billed for high-power installations, using direct metering (of the reactive power in kvar) or indirect metering (of the apparent power in kVA). Low power installations are billed in kW and therefore their only disadvantage is the limitation of the available current.

For responsible energy management with the aim of making better use of resources, and in view of the increasing numbers of receivers with a poor power factor (electronic power supplies, low consumption light bulbs), billing should logically move towards taking reactive power into account, which the next generation of “intelligent” meters will be capable of doing. Compensation of small installations will then come into its own.

Recommended Reading – Mastering single line and wiring diagrams: Using circuit breaker for MV power factor correction

Mastering single line and wiring diagrams: Using circuit breaker for MV power factor correction

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2.3 Example of potential savings on an installation billed in kVA

An installation usually operates with a subscribed demand S of 160 kVA. The average value of tanφ read is 0.75 (estimated cos 0.8). At peak demand, the power reached is close to the subscribed demand. At its peak, this installation therefore consumes an active power P = UI√3 cosφ = 160 × 0.8 = 128 kW and a reactive power Q = P × tanφ = 128 × 0.75 = 96 kvar.

Setting a target value of tanφ at 0.4, it will be possible to reduce the reactive power consumption to Q = P (tan φi – tan φf) = 128 × (0.75 – 0.4) = 45 kvar.

  • The saving in the reactive power consumption is G = 96 – 45 = 51 kvar.
  • The power compensation Qc could be 50 kvar by default.
  • The power S for the subscribed demand then becomes S = √(P2 + Q2) = √(128)2 + (51)2 = 138 kVA.

All that remains is to compare the potential saving on the subscribed tariff with the necessary expenditure in terms of the installation of compensation capacitors. The payback time on such an investment is generally very fast and is justified as soon as tanφ exceeds 0.6.

This simplified approach may lead to a risk of overcompensation when the installation is not subject to high loads (for example, in the summer). This is why more or less detailed readings, depending on the complexity of the consumption cycles, are always recommended in practice.

Further Reading – Five actions to achieve excellent energy savings in old electrical installations

Five actions to achieve excellent energy savings in old electrical installations

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3. Calculation based on measured elements

Power measurements have changed a great deal due to the increasing complexity of the signals and current waveforms absorbed and as a consequence metering equipment has also advanced, to such a degree that one no longer talks about power measurement but power analysis.

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3.1. Power measurement

Power measurement is a one-off measurement that can provide useful information as to the operating conditions of an installation, but it remains more or less limited depending on the equipment used (direct access to cosφ, tanφ, and harmonic powers), may be marred by errors due to the waveforms and frequencies of the signals, and above all only provides an image at a given moment.

Figure 8 – Two-wattmeters method

Two-wattmeters method
Figure 8 – Two-wattmeters method
  • P1 = U13×I1×cos (U13×I1) = U13×I1
  • ⇒ P2 = U23×I2·cos (U23×I2) = U23×I2
  • I1 + I2 + I3 = 0 ⇒ I3 = – I1 – I2
  • ⇒ P = V1×I1 + V2×I2 – V3×I1 – V3×I2
  • P = I1 (V1 – V3) + I2 (V2 – V3) = I1×U13 + I2×U23 = P1 + P2

The total power in three-phase systems is obtained by adding together the readings from two wattmeters. The tanϕ is calculated the same way:
tanϕ = √3·(P1 – P2) / (P1 + P2).

In a balanced state, the reactive power Q can be measured using a single wattmeter. It is demonstrated that cos(U13×I1) = cos(π/2 – ϕ). The reactive power in three-phase systems is written Q = √3×P.

Figure 9 – A single-wattmeter method

A single-wattmeter method
Figure 9 – A single-wattmeter method

P = U23×I1×cos (U13×I1) = U23×I1

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3.2 Calculation for energy suppliers (small power plants)

For this type of installation, the independent power producer must supply the distribution company with an amount of reactive energy equal to a contractual share of its production of active energy during high-load times and peak periods.

In this case, the calculation of the capacitor bank must take the following into account:

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4. Conversion table

This table can be used to calculate (based on the power of a receiver in kW) the power of the capacitors to change from an initial power factor to a required power factor. It also gives the equivalence between cosϕ and tanϕ.

Table 1 – Power of the capacitors to be installed (in kvar) per kW of load

Power of the capacitors to be installed (in kvar) per kW of load
Table 1 – Power of the capacitors to be installed (in kvar) per kW of load

Example: 200 kW motor – cosϕ = 0.75 – cosϕ to be achieved: 0.93 – Qc = 200 × 0.487 = 98 kvar.

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Source: Legrand



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The art of load shedding and online


Introduction to load shedding

Load shedding is a controllable reduction of a predetermined amount of the load power consumption according to specific shedding criteria. The predetermined amount of load to be shed is traditionally determined according to an analysis of the dynamic security for a set of contingencies. In this case, look-up tables are prepared and the implementation of the load shedding is performed according to them.

The art of load shedding and online applications in a power system under an emergency state
The art of load shedding and online applications in a power system under an emergency state

A shedding lookup table is dependent on the operating conditions of the systems, its available topology, the available reserve, and the contingency. In addition, a look-up table must be updated for changes in the system. A look-up table determined for given operating conditions and a specific set of single contingencies might be not valid in the situation of multiple contingencies such as cascaded outages of lines.

The main objective of the load shedding is correcting an abnormal system state (explained in Section 2) to either the normal state or the alert state. For example, the balance of the generation and the load during abnormal operating conditions is a way for keeping the system’s stability.

Table of Contents:

  1. Reasons for load shedding
    1. Active Power Shortage
    2. Reactive Power Shortage
    3. Sudden and Large Changes
    4. Slow and Small Changes
  2. Power System Security and the System States
  3. Under Voltage Load Shedding (UVLS) Schemes
  4. Under Frequency Load Shedding (UFLS) – An Overview

1. Reasons for Load Shedding

The load shedding can be applied manually or automatically. In addition, automatic load shedding has many philosophies. For example, the automatic reactive load shedding depends on the value of the absolute frequency as a shedding criterion while with the proactive load shedding not only the absolute frequency is used as a shedding criterion but also the rate of change of frequency or even the acceleration of frequency.

Based on its definition, load shedding is a corrective action by which system overloads can be relieved. The system overload can be classified according to its root causes as:

1.1 Active Power Shortage

In this case, the available power production sources or generators are insufficient to meet the system demand. In this case, the main symptom of system overload is a drop in the average system frequency. The shedding criterion, in this case, is the value of the system frequency. In the frequency drops below a predetermined value, the load shedding is activated.

This is called Under Frequency Load Shedding (UFLS).

1.2 Reactive Power Shortage

In this case, the available capacity is capable to meet the load active power demand while the voltage at specific locations in the network is too low for appropriate power flow and load requirements. The shedding criterion, in this case, is the violation of the bus voltage magnitudes.

For this purpose, it is called Under Voltage Load Shedding (UVLS).

The UFLS and UVLS schemes can be considered as special protection or wide area protection systems that attempt to minimize the impact of disturbances and prevent either brownouts or blackouts in power systems. Both types of load shedding should have shedding algorithms. A load shedding algorithm defines the method(s) by which several loads will be switched-off (and switched-on again) automatically to keep the power consumption below a defined security level.

Based on their time-frames and magnitudes of the associated changes in the operating conditions, system overloads may be also classified as:

1.3 Sudden and Large Changes

In this case, a disturbance causes the system to rapidly move from the initial stable operation conditions, and the time needed to take appropriate corrective actions before a possible system collapse is very small. In this case, fully automated, fast, and appropriate corrective actions must be taken.

1.4 Slow and Small Changes

In this case, a disturbance causes slow changes with small amplitudes. Consequently, manual corrective actions are possible. Based on this classification, the appropriate load shedding scheme can be determined.

The UVLS schemes are integrated into utility electrical systems to operate as a last resort for the controllable shedding of specific amounts of loads at specific locations in the grid. This action can prevent the loss of a large amount of the load or the entire load due to uncontrolled cascading events.

In contrast, the UFLS is designed for use in either emergency or extreme states (see section 2).

The main objective is to stabilize the balance between the available generation and load before or after an electrical island has been formed i.e. the UFLS drops enough load to allow the frequency to stabilize. Therefore, the UFLS helps to prevent the complete blackout and allows faster system restoration in case of islanding. Typically, a UVLS responds directly to voltage conditions in a local area.

The goal of a UVLS scheme is to shed load to restore reactive power relative to demand, to prevent voltage collapse, and to contain a voltage problem within a local area rather than allowing it to spread in geography and magnitude. Load shedding is generally applied in steps. In each step, a specific amount of the load is dropped. If the first load-shedding step does not allow the system to rebalance, and voltage continues to deteriorate, then the next block of the load is dropped.

The UFLS operates in the same manner.

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2. Power System Security and the System States

Power system security may be defined as the continuous ability of the power system to keep all the system limits not violated with minimum interruption to the supplied loads. The main target of the power system security is to keep the system intact under normal and disturbed conditions. Therefore, a successful security system should minimize the impact of disturbances on the operation, economics, and power quality of power systems.

In addition, an acceptable system security level guarantees the immunity of the power system to disturbances and makes the system defensive. Therefore, secure operation of power systems requires the integration of all practices designed for keeping acceptable system operation when components fail.

Power system security covers both static and dynamic phenomena. Therefore, the security analysis is usually categorized into static (or adequacy) and dynamic security.  Static security considers the impact of static or slow changes in the system limits while dynamic security considers the impact of disturbances (or contingencies) on the system.

The core definition of dynamic security and stability is the same, but the security is a wider term than stability.

System Stability Definition

Stability is defined as:

“The ability of an electric power system, for a given initial operating condition, to regain a state of operating equilibrium after being subjected to a physical disturbance, with most system variables bounded so that practically the entire system remains intact”; however, “Security not only includes stability but also encompasses the integrity of a power system and assessment of the equilibrium state from the point of view of overloads, under- or over- voltages and underfrequency”.

The system limits define the normal operation of power systems. These limits or constraints can be classified into two categories; equality and inequality constraints. In addition, the system limits may be classified according to their origin into intrinsic limits and operating range limits. The equality constraints basically represent the load flow equations while the inequality constraints represent the allowable range of acceptable operation of various components in the system.

In fact, the intrinsic and operating range limits elaborates on the inequality constraints associated with a specific component. The intrinsic limits of equipment are determined basically from the design and characteristics of the equipment. The operating range limits are generally less than the intrinsic limits and they are limited by the fulfillment of the overall operational requirements of the system.

For example, consider a simple hypothetical system where an off-grid generating plant supplies a load center via a short transmission line with negligible impedance. The generator is capable of producing a voltage magnitude at its terminal in the range 85% – 115% while the load requires a voltage magnitude in the range 95% – 105%.

In this case, the generator voltage limits present the intrinsic limits of the generator and they are mostly related to its design. Successful operation requires that the voltage magnitude at the load bus should not be violated.

Therefore, the operating range limits of the generator bus-voltage magnitude becomes equal to the load requirements (i.e. 95% – 105%). It is worthy to be mentioned that the 95% – 105% voltage limits present an intrinsic limit as viewed from the load perspective.

It is also important to know that the operating range limits should not violate the intrinsic limits of any component within a system. Otherwise, the system will be incapable of fulfilling the operational requirements. Both intrinsic and operating range limits are not absolute constants. The intrinsic capability limits usually decline with time due to the degradation of the equipment.

For example, the annual output degradation rate of PV systems is about 0.7%. The degradation may be attributed to aging, operational stresses, and maintenance quality.

The operating range limits are also variable. For example, the ampacity (or ampere capacity or current limits) of a cable is highly dependent on the temperature of its surroundings. The ampacity limits are usually increased during the winter and decreased during the summer. This is for avoiding the over-temperature of the cable insulation.

Recalling that in the normal operation of a power system, all the inequality and equality constraints of the system are satisfied. In addition, the system security requires a minimum available, reserve margin. Power system security may also be defined as the ability of the system to withstand credible contingencies without violating the normal operating limits.

A system operating under normal conditions is also said to operate in the normal state. The security strength of the system is usually defined by the maximum number of time-independent, and simultaneous disconnection of major system components (such as generators, transformers, and lines) without affecting the normal operation of the system.

Defining N as the minimum number of components required to supply the system peak load. A system with an N-k security criterion is a system in which k components may be simultaneously disconnected and the system will be able to fulfill the normal state requirements in the post-contingencies time. Due to investment constraints, power systems are usually designed according to the N-1 security criterion.

The normal state is a secure state and a system operating in the normal state is said to be intact.

Deviations from the normal state requirements cause the system operation to move to insecure operating states. These deviations are mainly caused by contingencies which are stochastic and unexpected events; however, the rate of contingencies may be reduced for example by proper maintenance of components. Four insecure operating states can be realized.

These states are the alert, emergency, extreme (or collapse), and restoration states.

State transition diagram
Figure 1 – State transition diagram

Figure 1 illustrates the main operational characteristics of these states and the interrelations between them. This figure is usually called the state transition diagram. Table 1 summarizes the characteristics of various states, some causes of state transitions, and examples of the corrective actions for each state. The nomenclature used in the table is illustrated in Figure 1.

It is worthy to be mentioned here that an intact system is capable of providing power balance. If the power balance could not be achieved, then the system becomes not intact. Consequently, the synchronization of generators upsets. Therefore, the system frequency protection devices will split the system into parts or islands; the situation is called islanding and it is within the extreme state.

The frequency and power balance conditions in each island are different and abnormal. Therefore, system blackout or unintentional brownout is usually detected. Delay in activating the possible corrective actions while the system is in the emergency state may be the main cause of the transition to the extreme state.

Generally, delayed or unsuccessful corrective actions during the operation in any state may lead to severe consequences. Therefore, any security program includes a contingency analysis block. The contingency analysis is an investigative simulation of hypothesized contingency for evaluating their impact on system security.

On the other hand, the corrective action analysis is the process of figuring the possible actions that may be taken for overcoming the consequences of security upsetting contingencies.

Table 1 – Summary of operating states and state transitions

State E I N-1 N Intact System Causes of transition from normal state Corrective Actions
Normal Yes
Alert Yes Constraints are near their limits. Examples, reduction in the reserve margin or bus voltage close to the limits. Preventive control. Examples, startup of the nonspinning reserve or switching on compensators respectively.
Emergency Yes Severe disturbances. For example: short-circuit faults or cascaded outages. Emergency control actions (heroic measures). Example: fast fault isolation or operation of reclosers.
Extreme No Delayed or unsuccessful emergency control actions. Severe power imbalance. Heroic and remedial actions such as load shedding, generator trip, or intentional islanding for keeping power balance.
Restoration No The attempt of restoring the system to the normal state or at least to the alert state. Manual or automated reinsertion of generators and loads. The inequality constraints should be kept satisfied during the entire restoration process.

The corrective action analysis works in two distinct modes. The first mode operates for solving the problems found by the contingency analysis. Therefore, this mode is offline while the second mode operates in real-time operation for securing the system during its real-time operation.

The contingency analysis and the corrective action analysis require the simulation of the system. Therefore, an accurate system model should be available. In addition, the results obtained from these analyses are highly dependent on the accuracy of the system model. Real-time models of a power system require centralized real-time data collection available from local measuring and monitoring devices at each system component

Therefore, telemetry is required for communication within the system and for estimating its state.

[highlght2]Recommended Reading[/highlight2] – 5 telecommunication systems embedded in smart grid applications and services

Five telecommunication systems embedded in smart grid applications and services

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3. Under Voltage Load Shedding (UVLS) Schemes

As a result of a disturbance, the voltage magnitude may drop to a preselected level for a predetermined time. In such cases, the UVLS sheds a selected amount of loads at selected locations in the system. The objective is then to prevent widespread voltage problems or voltage collapse. System planning engineers perform numerous studies (see Figure 2) using the PV curves as well as other analytical methods for the proper determination of the minimum amount of load that must be shed for securing the system to retain voltage stability under credible contingencies.

Various voltage control equipment provides a defense against voltage collapse; however, in situations, the system is subjected to severe disturbances or cascaded outages, various voltage control and voltage restoration equipment may fail to restore the normal state voltage range.

In these situations, the load shedding provides an effective corrective action for preventing either the voltage collapse or the islanding of the system.

This is illustrated in Figure 3. The shown voltage problems are attributed to the insufficiency of the reactive power sources needed for restoring an acceptable voltage level.

Voltage security assessment algorithms
Figure 2 – Voltage security assessment algorithms

It should be noted that system operators usually shed load as the last resort.

Under Voltage Load Shedding (UVLS) schemes, drops a load when the voltage gets too low. The dropping of the load will alleviate the system by eliminating the current flowing to the dropped load. UVLS usually triggers distribution feeders to open when the voltage of the bulk electric system is around 90%. Definite time relays usually act when all three phases show low voltage for around 10 seconds at 90% voltage magnitude, this would be after some of the ULTC transformers have been acted.

Certain critical customers cannot be dropped from load despite the help it may present to the system. Critical customers include hospitals or customers that would lose lots of revenue from being dropped.

The order of various corrective events following a contingency is shown in Figure 3.

Long-term (slow dynamic) voltage security and corrective actions
Figure 3 – Long-term (slow dynamic) voltage security and corrective actions

The events started as a response to a contingency such as a forced outage of a generator or a line. Erroneous operation or vandalism may also cause disturbances of a similar impact.

There are two main UVLS schemes:

  1. Decentralized (also called distributed UVLS) and
  2. Centralized schemes.

With a decentralized scheme, protection relays are installed at the loads that are a candidate to be shed upon severe voltage problems. As voltage conditions at these locations begin to collapse, the load assigned to that relay is automatically shed. On the other hand, a centralized scheme has undervoltage relays installed at key system buses within system areas. The trip information is transmitted to shed loads at various locations. Both schemes require high-speed and reliable communication for proper operation.

Figure 4 illustrates a typical distribution substation with integrated UVLS and UFLS special protections.

In this system, the UV relay is installed on the HV side of the transformer for the correct detection of the grid voltage. This is because the voltage on the secondary side is not a real indication of the grid voltage due to the actions of the ULTC transformer (or any other load side voltage controllers). The UF relay is installed on the LV side of the transformer because the transformer does not affect the frequency while the LVPT is more economical in comparison with the HVPT.

The main complication associated with the setting UVLS is the inaccuracies associated with the PT and the UV relay. Therefore, a proper and secure setting should be chosen for considering the probable inaccuracies.

A typical distribution substation with integrated UVLS and UFLS special protections
Figure 4 – A typical distribution substation with integrated UVLS and UFLS special protections

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4. Under Frequency Load Shedding (UFLS) – An Overview

In this section, an overview of the UFLS schemes and technologies will be presented. Generally, the system frequency is a good indicator of the power balance and overload
conditions in a power system. The UFLS is the last resort for the treatment of serious frequency declines in power systems when subjected to large disturbances.

Under the emergency state or the extreme state, the ability to maintain the power balance and stabilize the frequency is directly related to the effectiveness of the employed UFLS Strategy.

An effective UFLS strategy should be capable of:

  1. Restrain the frequency decline,
  2. Restore the normal frequency,
  3. Minimize the load shedding,
  4. Minimize the frequency recovery time,
  5. Minimize the frequency fluctuations, and
  6. Provide the desired protection functions as economical as possible.

Typically, a UFLS scheme sheds the loads in several stages. In each stage, a predefined amount of the load is disconnected and the shedding of the load is continued till the normal frequency (i.e. the power balance) is restored. This is illustrated in Figure 5 below.

In 50 Hz systems, the common practices of most utilities use 49.3 Hz (i.e. 1.4% drop in the frequency) as the first frequency step, and between 48.5 and 48.9 Hz for the last step. In proper dynamic control of power systems, a sufficient time delay must be left between the shedding of each load block. This is of major importance for monitoring the correct impact of disconnecting a load block on the system frequency and for avoiding excessive, unnecessary load shedding as well as for avoiding subjecting the system to over-frequency conditions due to the over – shedding of loads.

The proper timing of shedding each load block should not only depend on the frequency but also the rate of change of the frequency. This results in an adequate time separation between the shedding of blocks.

Using small load shedding blocks in conjunction with shedding timing based on the rate of change of frequency can be an effective way to the prevention of over-shedding.

UFLS conceptual operation – blocks of load shedding in k-stages scheme
Figure 5 – UFLS conceptual operation – blocks of load shedding in the k-stages scheme

The blocks of load shedding shown in Figure 5 can be selected based on two criteria; the static criterion and the dynamic criterion. Figure 6 shows flowcharts describing the logic of each criterion. In the static criterion, fixed load blocks are disconnected in each load shedding stage. This criterion may reduce the impact and the effectiveness of the load shedding, especially in large disturbance conditions that are associated with a steep decline in the frequency.

The dynamic load shedding is constructed for solving this problem. In the dynamic load shedding the amount of load to be disconnected at each shedding stage is dynamically selected based on the system frequency, the rate of change in the frequency, the voltage, and the severity of the disturbance(s).

In other words, the amount of a load shedding block is a function of the magnitude of the power imbalance.

UFLS criteria; (a) Static (semi-adaptive) UFLS; (b) Dynamic (adaptive) UFLS
Figure 6 – UFLS criteria; (a) Static (semi-adaptive) UFLS; (b) Dynamic (adaptive) UFLS

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There are three main methods for the implementation of UFLS strategies. These methods are:

4.1 The traditional method

When the frequency is lower than the first setting value, the first level of load shedding will be implemented. If the frequency continues to decline, it is clear that the first load shed amount is insufficient. When the frequency is lower than the second setting value, the second stage of load shedding is then implemented. If the frequency continues to decline, the further load shed stages are activated until the normal frequency value is restored.

The traditional method follows the static shedding criteria and the amount of load shedding per each shedding stage is determined based on the analysis of the worst possible expected events. Therefore, for less severe events, the first stage of shedding may result in an over-shedding and may also cause over-frequency problems.

4.2 The semi-adaptive method

To some extent, this method is similar to the traditional method; however, the specific amount of load to be shed is determined in terms of the measuring value of the rate of change of frequency.

4.3 The self-adaptive method

The self-adaptive method follows the dynamic shedding criterion for a more accurate estimation of the proper amounts of the load to be shed in each stage and the timing of each stage.

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How to measure power quality? What devices


Measurement of power quality

Measuring power quality and finding a bugbear in the network which is messing with the power are considered a highly paid job. Every electrical network and its problems with harmonics, transients, or disturbances are unique and need careful planning, setting the stage, measuring, and finally understanding where the problem is. That’s what power-quality engineers do.

How to measure power quality? What devices should you use and what to measure?
How to measure power quality? What devices should you use and what to measure?

This technical article is not about the basics of power quality, but the power quality instruments, how to read data, and what to measure. Measurement of power quality requires the use of proper instrumentation to suit the application. The user of the instrument must be well trained in the use and care of the instrumentation.

The engineer should be knowledgeable in the field of power quality.

Most importantly, the engineer should be safety conscious. All these factors are equally important in solving power quality problems. It’s important to note that power quality work requires patience, diligence, and perseverance. It is very rare that the solution to a problem will present itself accidentally, although it does happen occasionally.

Power quality work has its rewards. One that every power quality engineer cherishes the most is the satisfaction of knowing that he has left clients happier than when he first met them. That’s what they do, every time.

Table of Contents:

  1. Harmonic Analyzers
  2. Transient-Disturbance Analyzers
  3. Oscilloscopes
  4. Data Loggers And Chart Recorders
  5. True Rms Meters
  6. Instrument Setup Advice

1. Harmonic Analyzers

Harmonic analyzers or harmonic meters are relatively simple instruments for measuring and recording harmonic distortion data. Typically, harmonic analyzers contain a meter with a waveform display screen, voltage leads, and current probes.

Some of the analyzers are handheld devices and others are intended for tabletop use. Some instruments provide a snapshot of the waveform and harmonic distortion pertaining to the instant during which the measurement is made. Other instruments are capable of recording snapshots as well as a continuous record of harmonic distortion over time.

Obviously, units that provide more information cost more. Depending on the power quality issue, snapshots of the harmonic distortion might suffice. Other problems, however, might require knowledge of how the harmonic distortion characteristics change with plant loading and time.

What is the largest harmonic frequency of interest that should be included in the measurement?

According to Sankaran’s experience (the author of the book “Power Quality”), measurements to the 25th harmonics are sufficient to indicate the makeup of the waveform. Harmonic analyzers from various manufacturers tend to have different, upper-harmonic-frequency measurement capability.

Harmonic distortion levels diminish substantially with the harmonic number. In order to accurately determine the frequency content, the sampling frequency of the measuring instrument must be greater than twice the frequency of the highest harmonic of interest. This rule is called the Nyquist frequency criteria.

According to Nyquist criteria, to accurately determine the frequency content of a 60-Hz fundamental frequency waveform up to the 25th harmonic number, the harmonic measuring instrument must have a minimum sampling rate of 3000 (25 × 60 × 2) samples per second.

Figure 1 – Current clamp for measuring currents with waveform distortion due to harmonics

Current clamp for measuring currents with waveform distortion due to harmonics
Figure 1 – Current clamp for measuring currents with waveform distortion due to harmonics

Of course, higher sampling rates more accurately reflect the actual waveform. Measurement of voltage harmonic data requires leads that can be attached to the points at which the distortion measurements are needed. Typical voltage leads are 120 to 180 cm long. At these lengths, cable inductance and capacitance are not a concern, as the highest frequency of interest is in the range of 1500 to 3000 Hz (25th to 50th harmonic); therefore, no significant attenuation or distortion should be introduced by the leads in voltage distortion data.

Measuring current harmonic distortion data requires some special considerations. Most current probes use an iron core transformer designed to fit around the conductors in which harmonic measurements are needed. See Figure 1.

Iron-core current probes are susceptible to an increased error at high frequencies and saturation at currents higher than the rated values. Prior to installing current probes for harmonic distortion tests, it is necessary to ensure that the probe is suitable for use at high frequencies without a significant loss in accuracy.

Manufacturers provide data as to the usable frequency range for the current probes. The probe is useful between the frequencies of 5 Hz and 10 kHz for a maximum current rating of 500 A RMS.

Figure 2 – Handheld harmonic analyzer showing voltage leads and current probe for voltage and current harmonic measurements

Handheld harmonic analyzer showing voltage leads and current probe for voltage and current harmonic measurements
Figure 2 – Handheld harmonic analyzer showing voltage leads and current probe for voltage and current harmonic measurements

It should be understood that, even though the probe might be rated for use at the higher frequencies, there is an accompanying loss of accuracy in the data. The aim is to keep the loss of accuracy as low as possible. At higher frequencies, currents and distortions normally looked at are considerably lower than at the lower frequencies, and some loss of accuracy at higher frequencies might not be all that important.

Typically, a 5.0% loss in accuracy might be expected, if the waveform contains significant levels of higher-order harmonics.

Figure 2 shows the use of a handheld harmonic measuring instrument. This particular instrument is a single-phase measurement device capable of being used in circuits of up to 600 VAC.

Table 1 provides a printout of harmonic distortion data measured at a power distribution panel supplying a small office building.

Table 1 – Voltage and Current Harmonic Spectrum at an Office Building

Voltage and Current Harmonic Spectrum at an Office Building
Table 1 – Voltage and Current Harmonic Spectrum at an Office Building

The table shows the voltage and current harmonic information to the 31st harmonic frequency. Along with harmonic distortion, the relative phase angle between the harmonics and the fundamental voltage is also given. The phase angle information is useful in assessing the direction of the harmonic flow and the location of the source of the harmonics.

Figure 3 – Three-phase harmonic and disturbance analyzer

Three-phase harmonic and disturbance analyzer for measuring voltage and current harmonics, voltage and current history over a period of time, voltage transients, and power, power factor, and demand
Figure 3 – Three-phase harmonic and disturbance analyzer for measuring voltage and current harmonics, voltage and current history over a period of time, voltage transients, and power, power factor, and demand

A point worth noting is that the harmonics are shown as a percent of the total RMS value. IEEE convention presents the harmonics as a percent of the fundamental component. Using the IEEE convention would result in higher harmonic percent values. It does not really matter what convention is used as long as the same convention is maintained throughout the discussion.

Figure 3 shows a harmonic analyzer for measuring harmonic distortion snapshots and harmonic distortion history data for a specified duration.

Figure 4 provides the current waveform and a record of the current history at the panel over 5 days. The harmonic distortion snapshots along with the history graph are very useful in determining the nature of the harmonics and their occurrence pattern.

Figure 4 – Current waveform and current history graph at a lighting panel supplying fluorescent lighting

Current waveform and current history graph at a lighting panel supplying fluorescent lighting
Figure 4 – Current waveform and current history graph at a lighting panel supplying fluorescent lighting

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2. Transient-Disturbance Analyzers

Transient-disturbance analyzers are advanced data acquisition devices for capturing, storing, and presenting short-duration, subcycle power system disturbances. As one might expect, the sampling rates for these instruments are high.

It is not untypical for transient-disturbance recorders to have sampling rates in the range of 2 to 4 million samples per second. Higher sampling rates provide greater accuracy in describing transient events in terms of their amplitude and frequency content. Both these attributes are essential for performing transient analysis.

Figure 5 – Power Quality and Transient-Disturbance Analyzer

Transient-Disturbance Analyzer
Figure 5 – Transient-Disturbance Analyzer

The amplitude of the waveform provides information about the potential for damage to the affected equipment. The frequency content informs us as to how the events may couple to other circuits and how they might be mitigated.

Figure 6 shows a transient that reached a peak amplitude of 562 V with frequency content of approximately 200 kHz. Once such information is determined, equipment susceptibility should be determined. For instance, a 200-V peak impulse applied to a 480 V motor might not have any effect on motor life; however, the same impulse applied to a process controller could produce immediate failure.

Equipment that contains power supplies or capacitor filter circuits is especially susceptible to fast rise-time transients with high-frequency content.

Figure 6 – Switching transient disturbance with a peak of 562 V and a frequency content of 20 kHz

Switching transient disturbance with a peak of 562 V and a frequency content of 20 kHz
Figure 6 – Switching transient disturbance with a peak of 562 V and a frequency content of 20 kHz

When measuring fast rise time or higher frequency transients, the length of the wires used to connect the instrumentation to the test points becomes very important. In all of these measurements, the leads should be kept as short as possible.

Typically, lead lengths of 180 cm or less should not introduce significant errors in the measurements of fast transients. At higher frequencies, cable inductance, as well as capacitance, become important factors. The use of longer cable lengths in transient measurements results in higher inductance and capacitance and greater attenuation of the transient waveform.

Also, in order to minimize noise pickup from external sources, the voltage leads should be kept away from high-voltage and high-current conductors, welding equipment, motors, and transformers. The leads should be kept as straight as possible without sharp bends or loops. In any case, the excess lead length should never be wound into a coil.

Current transformers used in transient current measurements must have a peak current rating at least equal to the maximum expected currents; otherwise, current peaks are lost in the data due to the saturation of the current probe.

Figure 7 indicates how current probe saturation resulted in a flat-top current waveform and loss of vital information, making power quality analysis more difficult.

Figure 7 – Current transformer saturation resulting in the loss of vital peak current information

Current transformer saturation resulting in the loss of vital peak current information
Figure 7 – Current transformer saturation resulting in the loss of vital peak current information

Go back to Contents Table ↑

3. Oscilloscopes

Oscilloscopes are useful for measuring repetitive high-frequency waveforms or waveforms containing superimposed high-frequency noise on power and control circuits. Oscilloscopes have e sampling rates far higher than transient-disturbance analyzers.

Oscilloscopes with sampling rates of several hundred million samples per second are common. This allows the instrument to accurately record recurring noise and high-frequency waveforms.

Figure 8 shows the pulse-width-modulated waveform of the voltage input to an adjustable speed AC motor. Such data are not within the capabilities of harmonic analyzers and transient-disturbance recorders. Digital storage oscilloscopes have the ability to capture and store waveform data for later use.

Figure 8 – The pulse-width-modulated waveform from an adjustable speed drive output

The pulse-width-modulated waveform from an adjustable speed drive output
Figure 8 – The pulse-width-modulated waveform from an adjustable speed drive output

Using multiple-channel, digital storage oscilloscopes, more than one electrical parameter may be viewed and stored.

Figure 9 shows the noise in the ground grid of a microchip manufacturing facility that could not be detected using other instrumentation. The noise in the ground circuit was responsible for the production shutdown at this facility. The selection of voltage probes is essential for the proper use of oscilloscopes. Voltage probes for oscilloscopes are broadly classified into passive probes and active probes.

Passive probes use passive components (resistance and capacitance) to provide the necessary filtering and scale factors necessary. Passive probes are typically for use in circuits up to 300 VAC. Higher voltage passive probes can be used in circuits of up to 1000 VAC.

Figure 9 – Electrical noise in the ground grid of a computer center at a microchip manufacturing plant

Electrical noise in the ground grid of a computer center at a microchip manufacturing plant
Figure 9 – Electrical noise in the ground grid of a computer center at a microchip manufacturing plant

Most passive probes are designed to measure voltages with respect to ground. Passive probes, where the probe is isolated from the ground, are useful for making measurements when the connection to the ground is to be avoided. Active probes use active components such as field-effect transistors to provide high input impedance to the measurements.

High input impedance is essential for measuring low-level signals to minimize the possibility of signal attenuation due to loading by the probe itself.

Active probes are more expensive than passive probes. The high-frequency current probe is an important accessory for troubleshooting problems using an oscilloscope. By using the current probe, stray noise and ground loop currents in the ground grid can be detected.

Figure 10 – Power analyzer oscilloscope style with modular inputs

Power analyzer oscilloscope style with modular inputs
Figure 10 – Power analyzer oscilloscope style with modular inputs (photo credit: Yokogawa)

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4. Data Loggers And Chart Recorders

Data loggers and chart recorders are sometimes used to record voltage, current, demand, and temperature data in electrical power systems. Data loggers and chart recorders are slow-response devices that are useful for measuring steady-state data over a long period of time.

These devices record one sample of the event at a predetermined duration, such as 1 sec, 2 sec, 5 sec, etc. The data are normally stored within the loggers until they are retrieved for analysis. The data from data loggers and chart recorders are sufficient for determining the variation of the voltage or current at a particular location over an extended period and if there is no need to determine instantaneous changes in the values.

In some applications, this information is all that is needed.

But, in power quality assessments involving transient conditions, these devices are not suitable. The advantage of data loggers is that they are relatively inexpensive compared to power quality recording instrumentation. They are also easier to set up and easier to use. The data from the device may be presented in a text format or in a graphical format.

Figure 11 is the recording of current data at the output of a power transformer using a data logger. The data were produced at the rate of one sample every 5 sec. Data loggers and chart recorders are not intended for installation directly on power lines.

They are designed to operate using the low-level output of suitable voltage, current, or temperature transducers; however, care should be exercised in the installation and routing of the wires from the transducers to ensure that the output of the transducers is not compromised due to stray noise pickup.

Also, data loggers and chart recorders do not provide information about the waveshape of the measured quantity. If that level of information is needed, a power quality analyzer should be used instead.

Figure 11 – Current data from a data logger for one month of tests

Current data from a data logger for one month of tests
Figure 11 – Current data from a data logger for one month of tests

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5. True Rms Meters

The term true RMS is commonly used in power quality applications. What are true RMS meters? RMS value of the current or voltage can be substantially different from the fundamental component of the voltage or current. Using a meter that measures the average or peak value of a quantity can produce erroneous results if we need the RMS value of the waveform.

For waveforms rich in harmonics, the average and peak values would be considerably different than waveforms that are purely sinusoidal or close to sinusoidal. Measuring the average or peak value of a signal and scaling the values to derive an RMS value would lead to errors.

Figure 12 – True Rms Meter in action

Five power quality measurement devices that every engineer should know about
Figure 12 – True Rms Meter in action (photo credit: Fluke)

For example, consider a square wave of current as shown in Figure 13.

The average and peak reading meters indicate values of 111 A and 70.7 A RMS current, respectively. The square waveform has an average value of 100 A. The peak value of the waveform also has a value of 100 A. In order to arrive at the RMS value, the 100 A average value is multiplied by 1.11, The ratio between the RMS and the average value of a pure sinusoidal waveform is 1.11.

The peak reading meter would read the 100 A peak value and multiply it by 0.707 to arrive at the RMS value of 70.7 A, with 0.707 being the ratio between the RMS value and the peak value of a pure sinusoid waveform. The disparities in the values are quite apparent.

Figure 13 – Variation in rms measurements when using different types of meters

Variation in rms measurements when using different types of meters
Figure 13 – Variation in rms measurements when using different types of meters

Figure 13 also shows a triangular waveform and the corresponding current data that would be reported by each of the measuring instruments.

Analog panel meters give erroneous readings when measuring nonsinusoidal currents. Due to higher frequency components, analog meters tend to indicate values that are lower than the actual values. The presence of voltage and current transformers in the metering circuit also introduces additional errors in the measurements.

True RMS meters overcome these problems by deriving the heating effect of the waveform to produce an accurate RMS value indication. After all, RMS value represents the heating effect of a voltage or current signal. Most true RMS meters do not provide any indication of the waveform of the quantity being measured.

To accomplish this, the meters require high-frequency signal sampling capability. The sampling rate should satisfy Nyquist criteria in order to produce reasonably accurate results. Some benchtop RMS meters do have the sampling capability and ports to send the information to a computer for waveform display.

Go back to Contents Table ↑

6. Instrument Setup Advice

Setting up instruments to collect power quality data is probably the most critical aspect of testing and also one that most often can decide the end results. Setting up is a time when the utmost care must be exercised.

The first step is making sure to observe certain safety rules. In the majority of cases, the power to electrical equipment cannot be turned off to allow for instrument setup. The facility users want as few interruptions as possible, preferably none. Opening the covers of electrical switchboards and distribution panels requires diligence and patience. Personal protective equipment (PPE) is an important component of power quality testing.

IMPORTANT NOTE! Minimum PPE should contain electrical gloves, safety glasses, and fire-retardant clothing.

While removing panel covers and setting up instrument probes it is important to have someone else present in the room. The second person may not be trained in power quality but should have some background in electricity and the hazards associated with it.

Recommended reading – Electrical safety hazards awareness (with realistic work scenarios)

Electrical safety hazards awareness (with realistic work scenarios)

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Sources:

  • Power quality by Sankaran C.



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Hey engineers, wish you a happy and normal


Always look forward…

Just a short note from me today, the end of this crazy year. I’d like to wish you a normal and happy New Year on behalf of myself and everyone else at EEP. This year was like no other year before. The new ‘normal’ took the place of what we have known, which hurts in many ways and directions. Many things went wrong this year, and it appears that the main challenge for most of us in next year will be keeping the current jobs and healthy businesses.

Hey engineers, wish you a happy and normal new year, 2021!
Hey engineers, wish you a happy and normal new year, 2021!

However, despite all challenges, we managed to start the EEP Academy with few very experienced engineers. EEP Academy now has 40 high-quality courses, and there will be more in the coming months.

I always love to say that the only clever thing you can do is work hard on yourself and your knowledge. This is even more important in these challenging times. Success is always around the corner and will come sooner or later. Use everything you can to boost your electrical engineering knowledge and make yourself ready for future job opportunities.

EEP is always here to help you!

Now I want to share with you two opportunities we have: 20% discount on a Pro Premium Membership Plan and 30% discount on our electrical engineering courses at the EEP Academy.

Save 20% on EEP PRO Premium Membership

Apply discount code for Pro plan: EEP2020 (expires on January 4th, 2021)

Premium Pro membership plan gives you access to specialized LV/MV/HV technical articles written by experienced engineers and an advanced electrical guides and papers. You will see no distracting and annoying ads while reading technical articles. You will be able to print any technical articles in PDF format. This plan includes an Android application for accessing EEP’s both regular and premium resources on the go.

Sign up and apply the discount code. You can also see other premium plans.

Sign up to EEP Pro Plan

Get 30% off on all courses at the EEP Academy

Redeem coupon: EEP2020 (expires on January 4th, 2021)

What you can learn? Starting from the low voltage distribution design, PLC programming, solar energy systems, generators, transformers and transmission lines, power system analysis, load flow and short circuits. electricity and AC/DC circuits, you can learn symmetrical components of three phase power analysis, power transformers, protection and control of high voltage circuits, short circuit analysis, substation protection, etc. If you are serious in electrical design, you can learn to design electrical systems in the most popular software like ePlan or ETAP. See our course catalogue.

Sign up to EEP Academy, choose the courses or bundles, and redeem the coupon!

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May you all be safe, happy and successful in both professional and personal lives! Energy & Power For All in 2021!

Edvard Csanyi
Editor-In-Chief at EEP – Electrical Engineering Portal



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Ten most dangerous mistakes in the


Operation of Low-Voltage Switchgears

The Association of Steam and Electric Apparatus Owners (APAVE) generally classifies low-voltage equipment as any equipment that requires a rating of ≤ 1000 volts to operate. With a majority of electrically driven equipment falling under this category in industrial environments, this technical article focuses on highlighting dangerous mistakes that are inadvertently made in the operation of low-voltage switchgears which possess high hazardous potential to equipment and/or personnel.

Ten most dangerous mistakes in the operation of low voltage switchgear (you should be aware of)
Ten most dangerous mistakes in the operation of low voltage switchgear (you should be aware of)

Table of Contents:

  1. Bypassing Switchgear Protective Devices
  2. Switchgear Guiderails/Jaw Collectors
  3. Lock-out Tag-out Systems (LOTO)
  4. Isolator Switches (Operation On Load)
  5. Single Line diagram / Electrical Schematic Drawings
  6. Power Terminals: Verification of Torque Values
  7. Operation In Hazardous Areas
  8. Earth Switches
    1. Safe Operation of Earth Switches
  9. Minimum Safety Distance
  10. Personal Protective Equipment (PPE)

1. Bypassing Switchgear Protective Devices

The Austrian Accident Prevention Association (AUVA) in 2008, found that nearly 25% of all machine-related accidents occurred as a result of working around factory-installed protection devices.

More frequently than not, bypassing electrical protective devices such as Safety Relays, Emergency Shut-down (ESD) trip signals from a Process Safety System (PSS) and Emergency Push Buttons (EPBs) are subtly expected from Operations & Maintenance personnel due to perceived operational exigencies and management pressure to reduce production downtime.



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Troubleshooting the most typical winding


Recognizing motor winding problems

It’s always important to identify the real cause of burned windings and not just to replace the electric motor. Motor windings have a different appearance in all these failure situations: single-phase burnout, overload, unbalanced voltage, and voltage spikes. Voltage spike damage occurs more often in motors controlled by variable frequency drives.

Troubleshooting the most typical winding problems of three phase electric motors
Troubleshooting the most typical winding problems of three phase electric motors

These problems are all caused by in-plant faults that require correction. A replacement motor can fail sometimes immediately if the in-plant problem isn’t corrected.

It’s very important to accurately identify problems that require a motor’s removal and replacement. Winding problems that are identified should be documented. A history of the plant’s motor problems (on computer software) will point out problem areas that ran be improved, or even eliminated.

These winding problems may be found in a three-phase motor:

  1. Shorted turns
  2. Ground (winding shorted to frame)
  3. Phase-to-phase short
  4. Open winding
  5. Burned windings from operating on single phase
  6. Submerged motor
  7. Assorted rotor problems:
    1. Open rotor bars
    2. Open end rings
    3. Misaligned rotor/stator iron
    4. Rotor dragging on the stator
    5. Rotor loose on shaft

These problems require replacing or rewinding the motor.

1. Shorted Turns

A short is a common winding breakdown, and it requires rewinding or replacing the motor. Shorted turns are caused by nicked coil wire, high-voltage spikes, conductive contaminants, overheated winding, aged insulation, and loose, vibrating coil wires.

The most of the resistance to current flow in an AC motor is furnished by inductive reactance. The resistance of the wire in a complete phase is a very small percentage of the motor’s total impedance (resistance plus inductive reactance). Inductive reactance makes each turn very significant in the motor’s ampere demand. Each turn supplies much more inductive reactance than resistance.

A short forms when one or more turns of a coil are bypassed because of an insulation breakdown between wires. The resistance that the shorted turns develop is eliminated from its phase winding, resulting in increased amperes. When there are a few shorted turns in one of the three phases, a closed-loop circuit is formed by the turns within the short. As the motor runs, lines of force (from AC current flow) cut the wires in the closed-loop circuit.

A high circulating current is transformed into the loop (Figure 1a).

Transformed current flow in the turns within a shorted coil (dosed loop) raises the amperes of the phase
Figure 1 (a) – Transformed current flow in the turns within a shorted coil (dosed loop) raises the amperes of the phase

Power consumed by the circulating current increases the amperes of the faulty phase, making it easy to identify the problem. Circulating current in the closed loop often melts the circuit open. When this happens, the circulating current and the turns within the closed loop are eliminated.

See Figure 1(b).

Closed loop melted open
Figure 1 (b) – Closed loop melted open

Only the resistance of the wire (turns) within the closed loop is now eliminated from the phase winding. Without the ampere demand of the circulating current, the difference lessens between the amperes of the faulty phase and those of the normal phases.

A very small difference in resistance is all that is needed to identify the faulty phase. Please note that the rotor should be turned during this test to eliminate its effect. Shorted turns in any AC winding are usually visible. They become charred quickly from the high circulating current that is transformed into them (Figure 2).

Shorted coil example
Figure 2 – Shorted coil example

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2. Ground (winding shorted to frame)

When a motor is “grounded“, the winding is shorted either to the laminated core or to the motor’s frame. The problem is usually found in a slot, where the slot insulation has broken down. Water is the most common cause of a grounded winding. A solid ground requires rewinding or replacing the motor.

Some causes of slot insulation breakdowns are overheating, conducting contaminants, lightning, age, pressure of a tight coil fit, hot spots caused by lamination damage (from a previous winding failure), and excessive coil movement.

Excessive coil movement is often caused by thermal growth and/ or coil twisting torque, brought on by reversing (plugging) or a momentary power interruption.

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3. Phase-to-Phase Short

A phase-to-phase short is caused by insulation breakdown at the coil ends or in the slots. This type of fault requires rewinding or replacing the motor. Voltage between phases can be very high. When a short occurs, a large amount of winding is bypassed. Both phase windings are usually melted open, so the problem is easily detected.

Among the causes of interphase breakdown are contaminants, tight fit (in the slot), age, mechanical damage, and high-voltage spikes. Coils that form the poles for each phase are placed on top of each other in all three-phase motors.

Figure 3 is a concentric-type winding. The coils don’t share the slots with other poles in some concentric-type windings.

Windings of a concentric-wound stator
Figure 3 – Windings of a concentric-wound stator

Figure 4 is the lap-winding type. The ends of the coils are nested within each other and have phase insulation between the poles. The coils usually share the slots with other poles. Insulation also separates the coils of each phase in the slots. Some motors (up to 5 horsepower) are wound with no insulation separating the phases.

Phase-to-phase insulation is important because there is a line voltage potential between phases regardless of a motor’s horsepower.

Windings of a lap-wound stator
Figure 4 – Windings of a lap-wound stator (photo credit: ebielectric.com)

Figure 5 is an end coil phase-to-phase short. A phase-to-phase short occurs in the slot more often than at the coil ends. When a breakdown occurs in the slot, copper usually melts and fuses to the slot laminations.

This copper has to be ground out and removed before the motor is rewound, or it becomes a hot spot and deteriorates the new insulation.

Winding with a phase-to-phase short
Figure 5 – Winding with a phase-to-phase short

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4. Open Winding

A common cause of an open winding is undersized lead lugs. Charred connections in the motor’s connection (terminal) box are a sure indication of this problem. Open windings are also caused by shorted turns, phase-to-phase shorts, ground-to-frame shorts, faulty internal coil-to-coil connections, severe overloads, and physically damaged coils.

These faults require rewinding or replacing the motor. An open winding will show several different symptoms (depending on the motor’s internal connection).

A wye-connected motor with an open winding will test differently from a delta-connected motor. An open single-circuit winding will be “single-phased“. Its power will drop to about half, and the motor won’t start. If the motor’s internal connection is multicircuit, it will start but will have reduced power. An open circuit will cause the magnetic circuit to be unbalanced. Under normal load the motor will run more slowly and will overheat.

A microhmmeter is used to identify this problem. A motor with a high number of parallel circuits, that is, four and eight wye, will show less power loss when one circuit is open. Multiparallel circuit connections are used in motors above 5 horsepower. The windings of a severely overloaded motor (operating on 250 volts) usually become completely charred before an open winding occurs.

An overloaded motor operating on 490 volts, however, often will have no sign of burned wires before its windings melt open. In either case, the overload protection isn’t working, and the motor should be rewound or replaced.

Motor terminal box
Figure 6 – Motor terminal box

Motor lead connecting lugs should be thick enough (throughout the connection) to represent the circular mil area (size) of the motor’s lead wire. If any part of the lug is too small, it becomes a resistor in series with the motor, and current will be restricted when the motor needs it the most – to start the load.

Figure 7 shows lugs that aren’t made for electric motors. Lug (a) is a piece of copper tubing, which has been partially flattened and has a hole
punched in it for the connecting bolt. Its ferrule will hold wire that has a much greater circular mil area than that of the bolted part of the lug.

Lug (b) is clearly not a motor duty lug.

Two lead lugs that can cause motor failure
Figure 7 – Two lead lugs that can cause motor failure

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5. Burned Windings from Operating on Single Phase

When one line of a three-phase power supply opens, the power becomes single phase. If this happens while the motor is running, its power output is cut approximately in half. It will continue to run, but it can no longer start by itself. Like a single-phase motor without its start winding energized, it has no rotating magnetic field to get it started.

5.1 Single-Phase Damage to a Wye-Connected Nine-Lead Motor

Figure 8 shows the current path through the wye connection. Two phases of the windings are energized; the third phase has no current flow. If the motor’s protection device doesn’t function, the two phases that carry current will overheat and char The phase without current flow will look normal.

Schematic showing where the current flows in a wye-connected motor with line 3 open (single phase)
Figure 8 – Schematic showing where the current flows in a wye-connected motor with line 3 open (single phase)

Figure 9 is a picture of a single-phase-mused burnout in a four-pole winding.

A wye-connected motor that failed because of a single-phase condition. Line 3 is open.
Figure 9 – A wye-connected motor that failed because of a single-phase condition. Line 3 is open.

Single-Phase Damage to a Delta-Connected Nine-Lead Motor

Figure 10 shows the current path through the delta connection, with an open phase. The A phase has extremely high current flowing through it. The other two phases have about half as much. The phase with high current will overheat and char if the motor’s protection device doesn’t disconnect it.

The phases that carry less current will look normal.

Schematic showing where the current flows in a delta-connected motor with line 3 open (single phase)
Figure 10 – Schematic showing where the current flows in a delta-connected motor with line 3 open (single phase)

Figure 11 is a picture of a single-phase-mused burnout in a four-pole winding.

A delta-connected motor that failed because of a single-phase condition, Line 3 is open
Figure 11 – A delta-connected motor that failed because of a single-phase condition, Line 3 is open

Go back to Contents Table ↑

6. Submerged Motor

If a three-phase motor has been submerged in water but not energized, there’s a good chance it won’t need rewinding or replacing. Cleaning and baking the windings may be all that’s needed.

What should you do?

The motor should be disassembled as soon as possible. If the motor has ball bearings, they should be replaced. If it has sleeve bearings, the oil wicking material will pit or rust the shaft area located in the bearing window. Replace the oil wick material immediately. If the motor has an oil reservoir and oil ring, the reservoir should be thoroughly cleaned. The windings should be first tested with an ohmmeter.

A wet winding should never be subjected to a test voltage that could arc through the wet slot insulation.

The baking temperature shouldn’t exceed 93°C. The ohmmeter test should read infinity after baking. After the windings have been cleaned, dried, and tested, they will need a coat of air-drying varnish. When water soaks the slot insulation, the copper windings and the core become a form of battery. A small voltage can be read (with a millivoltmeter) between the winding and the frame when the slot insulation is wet.

A zero reading indicates the motor has been baked long enough. A megohmmeter, hi-pot, or surge tester can be used when an ohmmeter test shows infinity.

Further reading: Recommended maintenance practice for electric motors and generators

Recommended maintenance practice for electric motors and generators

Go back to Contents Table ↑

7. Most Common Rotor Problems

This is a review of the rotor problems found in Chapter 3, with more detailed information:

  1. Open rotor bars
  2. Open end rings
  3. Misaligned rotor/stator iron
  4. Rotor dragging on the stator
  5. Rotor loose on shaft

7.1 Open Rotor Bars

Open rotor bars or end rings usually necessitate replacing the motor. They can be repaired, recast, or rebarred (if it’s economical). It’s important that any replaced metal be the same as the original. See Figure 12.

Open rotor bars are usually caused by:

  • Overload burnout,
  • Arcing in the slot from a shorted winding,
  • Loose bar vibration,
  • Thermal growth stress (from starting),
  • Flaws in bar material (casting flaw), and
  • Poor connections with end rings.

Open rotor bars cause loss of power. If too many rotor bars are open, a loaded motor will draw amperes high enough to open its protection device. With no load, the amperes will be very low. Slow starting and lower-than-rated RPM are a sign of broken rotor bars.

Healthy rotor and rotors with one, two, and three broken bars
Figure 12 – Healthy rotor and rotors with one, two, and three broken bars

Go back to Contents Table ↑

7.2 Open End Rings

Open end rings muse uneven torque and some power loss. A ring with one open spot will soon develop more open spots. Each time the open spot crosses a 90° spot between poles, the current will double in the ring area between the next two poles. See Figure 13 below.

Causes of open end rings and/or cracked end rings include the following:

  • Flawed casting;
  • Motor burned out from overload;
  • Motor redesigned for a higher speed (without increased size of end ring);
  • Ring material drilled away for balancing; thermal growth stress; and
  • Mechanical damage.

A bubble or void in an end ring can cause an electrical vibration. This type of vibration can’t be corrected by balancing. It can be detected by cutting the power and allowing the motor to coast. Electrically mused vibrations will always cease as soon as the power is shut off.

Current flow in a squirrel cage rotor with an open end ring
Figure 13 – Current flow in a squirrel cage rotor with an open end ring

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7.3 Misaligned Rotor/Stator Iron

A motor with a misaligned rotor will draw high amperes and will lose power. The magnetic path becomes distorted, causing the magnetizing amperes to increase. The stator windings will char and resemble an overload burnout.

Possible causes of a misaligned rotor include:

  • Wrong bearing shim placement
  • Bearings not installed correctly on the shaft (extended race on wrong side)
  • Wrong bearing width
  • Captive bearing not held as originally placed
  • End bells interchanged
  • Stator core shifted on its shell
  • A rotor shifted on its shaft
  • A rotor replaced with a shorter rotor. A rotor with the same diameter but longer than the original will work, but some efficiency is lost.

Go back to Contents Table ↑

7.4 Rotor Dragging on the Stator

If the rotor drags on the stator and the bearings aren’t worn, it’s common practice to “skim” the rotor on a lathe. The process increases the air gap, which increases the no-load amperes. The increased amperes are similar to a misaligned rotor and stator iron. The magnetic circuit is degraded, so it takes more amperes to magnetize the motor’s iron.

The motor will run hotter than normal, because the motor is drawing more magnetizing amperes. If the load is at maximum or there are any adverse conditions (such as low voltage or frequent starts), the motor should be replaced. There will be some permanent power and efficiency loss.

Rotor Dragging on the Stator
Figure 14 – Rotor Dragging on the Stator

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7.5 Rotor Loose on Shaft

A loose rotor on a shaft makes a rumbling or vibrating sound. The sound will cease after the power is turned off (while the motor is coasting). If the motor has operated this way for very long, a red dust will form between the shaft and rotor iron. This dust is oxidized iron, caused by the rubbing action between the shaft and the rotor iron. The same thing happens when a pulley or bearing is loose on a shaft.

The decision to repair a loose rotor depends on the price of a replacement motor and the importance of the motor in the plant operation.

There are options for this problem:

  1. The rotor (and shaft) can be replaced;
  2. The rotor can be bored out and a new shaft fitted to it; or
  3. A thin metal wedge can be driven between the shaft and rotor to secure it.

Wedging the rotor may offset it enough to make it drag on the stator. It would then be necessary to skim the rotor-on a lathe-to keep it from dragging. The rotor should be bored and fitted with a new shaft. In most cases, it is more economical to replace the motor.

Go back to Contents Table ↑

Sources:

  1. Electric motor maintenance and troubleshooting by Augie Hand
  2. Detecting Broken Rotor Bars With Zero-Setting Protection by Carlos Pezzani, Pablo Donolo, and Guillermo Bossio (Universidad Nacional de Río Cuarto) and Marcos Donolo, Armando Guzmán, and Stanley E. Zocholl (Schweitzer Engineering Laboratories, Inc.)



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Your Cyber Monday in EEP! Save Big on


Great deal for engineers

Hello, hope all is well with you! It’s our pleasure to share with you two Cyber Monday deals for our new electrical engineers, expiring on December 3rd: 20% on EEP Pro Premium Membership and 30% off on all courses and bundles at the EEP Academy. This is an excellent opportunity to learn from specialized LV/MV/HV technical articles, online courses, guides, and papers.

Your Cyber Monday in EEP! Save Big on Premium Membership and Video Courses
Your Cyber Monday in EEP! Save Big on Premium Membership and Video Courses

So, let’s get in the Cyber Monday deals!

1. Save 20% on EEP PRO Premium Membership

Apply discount code (only for Pro plan): BLACKFRIDAY20

Premium Pro membership plan gives you access to specialized LV/MV/HV technical articles written by experienced engineers and an advanced electrical guides and papers. You will see no distracting and annoying ads while reading technical articles. You will be able to print any technical articles in PDF format. This plan includes an Android application for accessing EEP’s both regular and premium resources on the go.

Sign up to EEP Premium and use the discount code!

Sign up to EEP Premium

2. Get 30% off on all courses at the EEP Academy

Redeem coupon: BLACKFRIDAY20

What you can learn? Starting from the fundamentals of electricity and AC/DC circuits, you can learn symmetrical components of three phase power analysis, power transformers, protection and control of high voltage circuits, short circuit analysis, substation protection, etc. If you are serious in electrical design, you can learn to design electrical systems in the most popular software like ePlan or ETAP. See our course catalogue.

Sign up to EEP Academy, choose the courses and bundles, and redeem the coupon!

Sign up to EEP Academy

Look forward to hearing from you.

Have a wonderful day!

Kind regards,

EEP Editorial Team
https://electrical-engineering-portal.com
https://academy.electrical-engineering-portal.com



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The most used types of single-phase motors


10+ single-phase motors per home

You should know that single-phase motors are rarely rated above 5 kW. Fractional-kilowatt motors, most of which are single-phase, account for 80−90% of the total number of motors manufactured and for 20−30% of the total commercial value. A typical modern home may have 10 or more single-phase motors in its domestic electrical equipment.

Mastering single-phase motors
Mastering single-phase motors (photo credit: repulsionmotor-repair.business.site)

That makes single-phase motors the most used motor types in the world. Let’s get into these types one by one.

Table of contents:

  1. Series motor
    1. Universal motor
    2. Compensated motor
  2. Repulsion motor
  3. Induction motors
    1. Rotating-field theory
    2. Starting
    3. Shaded-pole motor
    4. Resistance split-phase motor
    5. Capacitor split-phase motor
    6. Repulsion-induction motor
      1. Repulsion-start motor
      2. Repulsion-induction motor

1. Series motor

As the direction of rotation and of torque in a DC series motor are independent of the polarity of the supply, such a motor can operate on AC provided that all ferromagnetic parts of the magnetic circuit are laminated to minimize core loss.

1.1 Universal motor

In the fractional-kilowatt sizes the series motor has the advantage, since it is non-synchronous, of being able to run at speeds up to 10 000 rev/min. It is very well adapted to driving suction cleaners, drills, sewing machines and similar small-power rotary devices.

Its facility of operating on DC and AC is not now important, but is the origin of the term “universal“.

The machine has a “series” speed-torque characteristic, the no-load speed being limited by mechanical losses. The power factor is between 0.7 and 0.9 (mainly the result of armature inductance), but this is of no significance in small ratings.

Typical characteristics for a motor for DC and 50 Hz supplies of the same nominal voltage are shown in Figure 1.

Characteristics of a 75 W universal motor
Figure 1 – Characteristics of a 75 W universal motor

In all AC commutator motors the commutation conditions are more onerous than on DC because the coils undergoing commutation link the main alternating flux and have e.m.f.s induced of supply frequency. The e.m.f.s are offered a short-circuited path through the brushes and contribute to sparking at the commutator.

As the e.m.f.s are proportional to the main flux, the frequency and the number of turns per armature coil, these must be limited. A further limit on the current in a short-circuited coil is provided by high-resistance carbon brushes.

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1.2 Compensated motor

Series AC commutator motors up to 700±800 kW rating are used in several European railway traction systems. For satisfactory commutation the frequency must be low, usually 16 2/3 Hz, and the voltage must also be low (400−500 V ), this being provided by a transformer mounted on the locomotive.

The inductance of the armature winding is necessarily rather high, so that a compensating winding must be fitted to neutralise armature reaction in order to ensure a reasonable power factor.

Motors of this type have been built, of limited output, for operation on modern 50 Hz traction systems but have now been superseded by rectifier- or thyristor-fed DC motors. See Figure 1a.

Series AC commutator motor
Figure 1a – Series AC commutator motor

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2. Repulsion motor

The repulsion motor is a form of series motor, with the rotor energized inductively instead of conductively. The commutator rotor winding is designed for a low working voltage. The brushes are joined by a short circuit and the brush axis is displaced from the axis of the one-phase stator winding (Figures 2, 3, and 4).

With non-reversing motors (Figure 2) a single stator winding suffices.

Repulsion non-reversing motor alternative form
Figure 2 – Repulsion non-reversing motor alternative form

However, for reversing motors the stator has an additional winding, connected in one or other sense in series with the first winding to secure the required angle between the rotor and effective stator axes for the two directions of rotation, as in Figure 3.

Repulsion two-directions motor alternative form
Figure 3 – Repulsion two-directions motor alternative form

A stator winding of N1 turns as in (a) can be resolved into two component windings respectively coaxial with and in quadrature with the axis of the rotor winding, and having respectively turns N1 sinα and N1 cosα. Windings (b) give the two axis windings directly, although here the turns can be designed for optimum effect.

The coaxial winding induces e.m.f.s and currents in the rotor, and these currents lying in the field of the other stator winding develop torque. Since both stator and rotor currents are related, the motor has a “series” characteristic. When the motor is running, the direct and quadrature axis fluxes have a phase displacement approaching 90°, so producing a travelling-wave field of elliptical form which becomes nearly a uniform synchronously rotating field at speeds near the synchronous.

Near synchronous speed, therefore, the rotor core losses are small and the commutation conditions are good.

Small motors can readily be direct-switched for starting, with 2.5−3 times full-load current and 3−4 times full-load torque. The normal full-load operating speed is chosen near, or slightly below, synchronous speed in order to avoid excessive sparking at light load.

Repulsion motor starting characteristics
Figure 4 – Repulsion motor starting characteristics

Repulsion motors are used where a high starting torque is required and where a three-phase supply is not available. For small lifts, hoists and compressors their rating rarely exceeds about 5 kW.

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3. Induction motors

The one-phase induction motor is occasionally built for outputs up to 5 kW, but is normally made in ratings between 0.1 and 0.5 kW for domestic refrigerators, fans and small machine tools where a substantially constant speed is called for. The behavior of the motor may be studied by the rotating-field or the cross-field theory.

The former is simpler and gives a clearer physical concept.

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3.1 Rotating-field theory

The pulsating m.m.f. of the stator winding is resolved into two “rotating” m.m.f.s of constant and equal magnitude revolving in opposite directions. These m.m.f.s are assumed to set up corresponding gap fluxes which, with the rotor at rest, are of equal magnitude and each equal to one-half the peak pulsating flux.

When the machine is running, the forward field component f, i.e. that moving in the same direction as the rotor, behaves as does the field of a polyphase machine and gives the component torque-speed curve marked “forward” in Figure 5.

The backward component b gives the other torque component, and the net torque is the algebraic sum. At zero speed the component torques cancel so that the motor has no inherent starting torque, but if it is given a start in either direction a small torque in the same direction results and the machine runs up to near synchronous speed provided that the load torque can be overcome.

Torque components in a single one-phase induction
Figure 5 – Torque components in a single one-phase induction

The component torques in Figure 5 are, in fact, modified by the rotor current. Compared with the three-phase induction motor, the one-phase version has a torque falling to zero at a speed slightly below synchronous, and the slip tends to be greater.

There is also a core loss in the rotor produced by the backward field, reducing the efficiency. Moreover, there is a double-frequency torque pulsation generated by the backward field that can give rise to noise.

The efficiency lies between about 40% for a 60 W motor and about 70% for a 750 W motor, the corresponding power factors being 0.45 and 0.65, approximately.

Simple one-phase induction motor: equivalent circuit
Figure 6 – Simple one-phase induction motor: equivalent circuit

The equivalent circuit of Figure 6 is based on the rotating-field theory, using parameters generally similar to those for the three-phase machine. The e.m.f.s Ef and Eb are generated respectively by the forward and backward field components and are proportional thereto.

The respective component torques are proportional to I2f2 × r2 / 2s and I2f2 × r2/ [2(2 − s)], the next torque being their difference.

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3.2 Starting

To start a one-phase induction motor, means are provided to develop initially some form of travelling-wave field. The arrangements commonly adopted give rise to the terms “shaded-pole” and “split-phase“.

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3.3 Shaded-pole motor

The stator has salient poles, with about one-third of each pole-shoe embraced by a shading coil. That flux which passes through the shading coil is delayed with respect to the flux in the main part of the pole, so that a crude shifting flux results.

The starting torque is limited, the efficiency is low (as there is a loss in the shading coil), the power factor is 0.5−0.6 and the pull-out torque is only 1−1.5 times full-load torque.

Applications include small fans of output not greatly exceeding 100 W.

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3.4 Resistance split-phase motor

The additional flux is provided by an auxiliary starting winding arranged spatially at 90°(electrical) to the main (running) winding. If the respective winding currents are Im and Is with a relative phase angle α, the torque is approximately proportional to ImIs sinα.

At starting, the main-winding current lags the applied voltage by 70−80°. The starting winding, connected in parallel with the main winding, is designed with a high resistance or has a resistor in series so that Is lags by 30−40°.

The effect of this resistance on the starting characteristic is shown in Figure 7(a). With given numbers of turns per winding and a given main-winding resistance, then for a specified supply voltage and frequency there is a particular value of starting-winding resistance for maximum starting torque.

Single-phase induction motor: split-phase resistance start
Figure 7 – Single-phase induction motor: split-phase resistance start

The relation can be obtained from the phasor diagram. Figure 7(b), in which V1 is the supply voltage and Im at phase angle Φm is the main-winding current. The locus of the starting-current phase Is with change in resistance is the semicircle of diameter OD (which corresponds to zero resistance). The torque is proportional to ImIs sin(Φm − Φs) and is a maximum for the greatest length of the line AC.

From the geometry of the diagram it can be shown that for this condition Φs = 1/2 Φm.

Direct switching is usual. To reduce loss, the auxiliary winding is open-circuited as soon as the motor reaches running speed. The starting torque for small motors up to 250 W is 1.5−2 times full-load torque, and that for larger motors rather less, in each case with 4−6 times full-load current.

The operating efficiency is 55−65% and the power factor 0.6−0.7.

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3.5 Capacitor split-phase motor

A greater phase difference (Φm − Φs) can be obtained if a series capacitor is substituted for the series resistor of the auxiliary winding. Maximum torque occurs for a capacitance such that the auxiliary current leads the main current by (1/2πα)/2.

The capacitor size is from 20−30 mF for a 100 W motor to 60−100 mF for a 750 W motor. For economic reasons the capacitor is as small as is consistent with producing adequate starting torque, and some manufacturers quote alternative sizes for various levels of starting torque.

If the capacitor is left in circuit continuously (capacitor-run) the power factor is improved and the motor runs with less noise. Ideally, however, the value of capacitance for running should be about one-third of that for the best starting. If a single capacitor is used for both starting and running, the starting torque is 0.5−1 times full-load value and the power factor in running is near unity.

Go back to Contents Table ↑

3.6 Repulsion-induction motor

Machines have been designed to combine the high starting torque capability of the repulsion motor with the constant-speed running characteristic of the induction motor.

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3.6.1 Repulsion-start motor

This motor has a stator winding like that of a repulsion motor and a lap commutator winding, with the addition of a device to short circuit the commutator sectors together by centrifugal action when the speed reaches about 75% of normal. The device may also release the brushes immediately thereafter.

Thus the commutator rotor winding becomes, in effect, a short-circuited “induction”-type winding for running.

Small motors direct-switched give 3−4 times full-load torque with about three times full-load current. Alower starting current is obtained by connecting a graded resistor in series with the stator winding.

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3.6.2 Repulsion-induction motor

The machine has a repulsion-type stator winding but the change from the repulsion-mode to the induction-mode operation is gradual as the machine runs up to speed. The rotor has two windings in slots resembling those of a double-cage induction motor. The outer slots carry a  commutator winding with brushgear, the inner slots contain a low-resistance cage with cast aluminium bars and end-rings, and its deep setting endows it with a high inductance.

During acceleration the reactance of the cage falls and its torque increases, tending to counterbalance the falling torque of the commutator winding. At speeds above synchronous the cage torque reverses, giving a braking action which holds the no-load speed to a value only slightly above synchronous speed.

The commutation is better than that of a plain repulsion motor, and the motor is characterised by a good full-load power factor (e.g. 0.85−0.9 lagging).

With direct switching the starting torque is 2.5−3 times and the current 3−3.5 times full-load value.

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Source: Electrical Engineer’s Reference Book by M. A. Laughton and D. J. Warne



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My experience in the first synchronization


Synchronization to the grid

Any power plant commissioning, from small industrial GTG (Gas-To-Gasoline) to nuclear facility, will converge to a very final step before (provisional) commercial operation, sometimes empathized as “first kW”: synchronization to local or national grid. This is in fact a very critical phase of the installation, where mistakes in pre-commissioning or forced control variables to bypass that last permissive preventing to close the main MV breaker can easily lead to a disaster.

My experience in the first synchronization of the MV generator in an industrial plant
My experience in the first synchronization of the MV generator in an industrial plant (original photo by Francesco Becattini)

As common sense would suggest, synchronization of generator and grid implies that three key parameters of the two waveforms match within a certain window:

  1. Frequency
  2. Voltage
  3. Phase Angle

This condition is verified by a synchro check device, that may be integrated in the main IED protecting the generator as ANSI 25C function and obtained acting on governor and AVR either manually or via an automatic synchronization card, that will send the closing command to the MV switchgear control circuitry finally closing the main circuit breaker (52G).

Check on instrumentation and protection

Before to initiate the synchronization sequence, regardless the fact that all factory test reports, precommissioning and commissioning certificates are available a final check of proper protective functions in live condition is due.

To perform this key activity all the instrumentation connected to protection relay including VT via (possibly) primary and secondary injection, and CT via polarity test must be rechecked. Obviously all other subsystems including prime mover and driven skid shall be fully commissioned, hardwired control loops checked (with special focus to trip signals), communication (soft link) established.

All panels including MV Switchgear station and excitation panel (AVR) shall be energized and ready.

Open circuit tests will be conducted at first possibly opening the earth switch (89) to test if it has been inserted for safety reasons, checking the expected behavior of voltage and frequency (ANSI 27, 59 and 81) trips, in accordance to the actions listed in trip matrix, that may include apart from open breaker command lockout relay engage (either electromechanical or logical) and other actions.

On phase 2 earth switch is closed to start the short circuit tests, that will imply a soft ramping of excitation current and measuring armature currents at different field excitation current. An ANSI 87 (differential) protection is simulated changing ratio of one CT.

In this phase both proper excitation system functioning and actions of differential system that being one of the cornerstone protections will usually trigger both a prime mover trip and a fast de-excitation of the generator.

Commissioning live tests on protective system
Figure 1 – Commissioning live tests on protective system

Phase 3 will involve an unbalance of the three phase system connecting to ground one of the phases and obviously removing the shorting link, in this way 51G and 67N protection (via toroidal or ZCT) will be tested.

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The essentials of power-generation systems


Generating source

When we talk about the power system, there are dozen of essential terms and definitions. One of the most important is for sure that any AC power system begins with a generating source. Electric generators are devices that convert energy from a mechanical form into an electrical form. This process, known as electromechanical energy conversion, involves magnetic fields that act as an intermediate medium.

The essentials of power-generation systems you MUST know in the middle of the night!
The essentials of power-generation systems you MUST know in the middle of the night! (on photo: Generator constructed in 1908, mounted in a hydro-power station in Lower Austria; credit: gue* via Flickr)

The input to the generating machine can be derived from a number of energy sources.

For example, in the generation of large-scale electric power, coal can produce steam that drives the shaft of the machine. Typically, for such a thermal process, only about 1/3 of the raw energy (i.e., from coal) is converted into mechanical energy. The final step of the energy conversion is quite efficient, with efficiency close to 100%.

Let’s get started with fundamental concepts of generators and control techniques:

  1. Fundamental Concepts
    1. Operating Principles
      1. Governor
      2. Damper Windings (Armortisseur Windings)
      3. Excitation Control System
  2. Control Techniques

1. Fundamental Concepts

A simplified diagram of a three-phase generator is shown in Figure 1. Note that poles A’, B’, and C’ represent the start of each of the phase windings, whereas poles A, B, and C represent the ends of each of the windings.

As with transformers, the windings of the generator can be connected in either of two ways:

  1. Wye configuration: A circuit arrangement in which the schematic diagram of the windings forms a Y.
  2. Delta configuration: A circuit arrangement in which the schematic diagram of the windings forms a delta.
Simplified diagram of a three-phase AC generator
Figure 1 – Simplified diagram of a three-phase AC generator

Figure 2 illustrates the connection arrangements. The generator shown in Figure 1 is a rotating-field type of device. A magnetic field is developed by an external DC voltage. Through electromagnetic induction, a current is induced into each of the stationary (stator) coils of the generator.

Generator circuit configurations: (a) wye; (b) delta
Figure 2 – Generator circuit configurations: (a) wye; (b) delta

Because each of the phase windings is separated by 120°, the output voltage of the generator also is offset for each phase by 120° (Figure 3). Three-phase power is used almost exclusively for power distribution because it is an efficient method of transporting electrical energy.

Output waveform of a three-phase generator
Figure 3 – Output waveform of a three-phase generator

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1.1 Operating Principles

The operation of a generator is based on Faraday’s law of electromagnetic induction: If a coil (or winding) is linked to a varying magnetic field, then an electromotive force (emf or voltage) is induced across the coil. Thus, generators have two essential parts: one that creates a magnetic field, and the other where the emf energies are induced.

The magnetic field is typically generated by electromagnets. Thus, the field intensity can be adjusted for control purposes. These windings are referred to as field windings or field circuits. The coils where the emf energies are induced are called armature windings or armature circuits.

One of these two components is stationary (the stator), and the other is a rotational part (the rotor) driven by an external torque.

Conceptually, it is immaterial which of the two components is intended to rotate because, in either case, the armature circuits always experience a varying magnetic field.

However, practical considerations lead to the common design that for AC generators, the field windings are mounted on the rotor and the armature windings on the stator.

Today, most electric power is produced by synchronous generators that rotate at a constant speed (the synchronous speed). This speed is dictated by the operating frequency of the system and the machine structure. AC generators are also used that do not necessarily rotate at a fixed speed, such as those found in windmills (induction generators); these generators, however, account for only a small percentage of the power generated today.

Cross section of a simple two-pole synchronous machine
Figure 4 – Cross section of a simple two-pole synchronous machine

For a better understanding of the principles of operation, see Figure 4, which shows a cross section of a basic AC machine. The rotor consists of a winding wrapped around a steel body. A DC current is made to flow in the rotor winding (or field winding), and this results in a magnetic field (rotor field). When the rotor is made to rotate at a constant speed, the three stationary windings aa’, bb’, and cc’ experience a periodically varying magnetic field.

Thus, an emf is induced across these windings in accordance with Faraday’s law. These forces are AC and periodic, each period corresponds to one revolution of the rotor.

Thus, for 60 Hz electricity, the rotor must spin at 3600 revolutions per minute (rpm); this is the synchronous speed of the machine. Because the windings aa’, bb’, and cc’ are displaced equally in space from each other (by 120°), their emf waveforms are displaced in time by one third of a period.

In other words, the machine is capable of generating three-phase electricity. When the stator windings are connected to an external (electrical) system to form a closed circuit, the steady-state currents in the windings are also periodic.

This revolving field arises from the space displacements of the windings and the phase differences of their currents. The combined magnetic field has two poles and rotates at the same speed and direction as the rotor. It is important to observe that the armature circuits are in fact exposed to two rotating fields, one of which (the armature field) is caused by and tends to counter the effect of the other (the rotor field).

The end result is that the induced emf in the armature can be reduced when compared with an unloaded machine (i.e., open-circuited stator windings). This phenomenon is referred to as armature reaction.

It is possible to build a machine with p poles, where p = 4, 6, 8, … (even numbers). For example, the cross-sectional view of a four-pole machine is illustrated in Figure 5. For the specified direction of the (DC) current in the rotor windings, the rotor field has two pairs of north and south poles, arranged as shown.

The emf induced in a stator winding completes one period for every pair of north and south poles sweeping by; thus, each revolution of the rotor corresponds to two periods of the stator emf.

If the machine is to operate at 60 Hz, then the rotor needs to rotate at 1800 rpm. In general, a p-pole machine operating at 60 Hz has a rotor speed of 3600/(p/2) rpm.

That is, the lower the number of poles, the higher the rotor speed must be. In practice, the number of poles is dictated by the mechanical system (the prime mover) that drives the rotor. Steam turbines operate best at a high speed; thus, two- or four-pole machines are suitable. Machines driven by hydro turbines usually have more poles and operate at lower speeds.

The stator windings are typically arranged so that the resulting armature field has the same number of poles as the rotor field.

A four-pole synchronous machine: (a) cross section of the machine; (b) schematic diagram for the phase a windings
Figure 5 – A four-pole synchronous machine: (a) cross section of the machine; (b) schematic diagram for the phase a windings

In practice, there are many possible ways to arrange these windings. The essential idea, however, can be understood by studying the arrangement shown in Figure 5. Each phase consists of a pair of windings and thus occupies four slots on the stator structure. For example, those for phase a are labeled a1a1′ and a2a2′.

Geometry suggests that, at any time instant, equal electromotive forces are induced across the windings of the same phase. If the individual windings are connected in series, as shown in Figure 5, their energies add up to form the phase voltage.

In addition to the basic components of a synchronous generator (the rotor, stator, and their windings), auxiliary devices are used to help maintain the machine’s operation within acceptable limits.

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These devices include the following:

1.1.1 Governor

The function of the governor is to control the mechanical power input to the generator. The control is via a feedback loop where the speed of the rotor is constantly monitored. For instance, if this speed falls behind the synchronous speed, the input is insufficient and has to be increased. This is accomplished by opening a valve to increase the amount of steam for turbogenerators or the flow of water through the penstock for hydrogenerators.

Governors are mechanical systems and, therefore, usually have some significant time lags (many seconds) compared to other electromagnetic parameters associated with the machine.

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1.1.2 Damper windings (armortisseur windings)

These windings are special conducting bars buried in notches on the rotor surface (the rotor resembles a squirrel-cage-rotor induction machine). The damper windings provide an additional stabilizing force for the machine during certain periods of operation. As long as the machine is in a steady state, the stator field rotates at the same speed as the rotor, and no currents are induced in the damper windings.

However, when the speeds of the stator field and the rotor become different (because of a load disturbance), currents are induced in the damper windings in such a way as to keep the two speeds from separating.

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1.1.3 Excitation control system

Modern excitation systems are fast and efficient. An excitation control system is a feedback loop designed to maintain the voltage at the machine terminals at a set level. Figure 6 illustrates the mechanisms at work.

The per-phase equivalent circuit of a round-rotor synchronous machine
Figure 6 – The per-phase equivalent circuit of a round-rotor synchronous machine

Where: EF is the internal voltage (phasor form) and Vt is the terminal voltage.

Assume that a disturbance occurs in the system, and as a result, the machine terminal voltage Vt drops. The excitation system boosts the internal voltage EF. This action can increase the voltage Vt and also tends to increase the reactive power output. From a system viewpoint, the two controlling mechanisms of excitation and the governor rely on local information (the machine terminal voltage and rotor speed).

In other words, they are decentralized controls. For large-scale systems, such designs do not always guarantee stable behavior because the effects of the interconnection system and other elements in the network are not taken into account.

An analysis of the operation of centralized control systems is beyond the scope of this article, however, it is instructive to examine some of the principles of decentralized control systems. Many of these principles apply in a modified form to centralized control techniques.

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2. Control Techniques

Reliable electric power service implies that the loads are fed at a constant voltage and frequency at all times. A stable power system is one in which the synchronous machines, if perturbed, will return to their original state if there is no net change in power, or stabilize at a new state without loss of synchronization.

The machine rotor angle is used to quantify stability; that is, if the difference in the angle between machines increases or oscillates for an extended period of time, the system is considered unstable. The swing equation, given by:

J × δ= J × ωm = Ta

governs the motion of the machine rotor. J is moment of inertia, δm is mechanical torque angle with respect to a rotating reference, ωm is shaft angular velocity, and Ta is the accelerating torque.

Two factors that act as criteria for the stability of a generating unit are the angular swing of the machine during and following fault conditions, and the time it takes to clear the transient swing.

The mechanical torque of the prime mover — team or hydraulic — for a large generator depends on rotor speed. In an unregulated machine, the torque speed characteristic is linear over the rated range of speeds. The prime mover speed of a machine will drop in response to an increased load, and the valve position must be opened to increase the speed of the machine.

The basic power circuit of a generating system
Figure 7 – The basic power circuit of a generating system; Vs = Eg – IaXg

In a regulated machine (governor controlled), the speed control mechanism controls the throttle valves to the steam turbine or the gate position for a water turbine. Automatic voltage regulation can be used to adjust the field winding current, thus changing Eg as the load on the machine is varied (Figure 7).

If the power output of a generator is to be increased while an automatic voltage regulator holds the bus voltage at a constant value, then the field winding current must be increased. The maximum voltage output of a machine is limited by the maximum voltage of the excitor supplying the field winding.

Figure 8 illustrates control of a power-generating unit.

Block diagram of a generating control system
Figure 8 – Block diagram of a generating control system

The performance of a transmission system can be improved by reactive compensation of a series or parallel type. Series compensation consists of banks of capacitors placed in series with each phase conductor of the line and is used to reduce the series impedance of the line, which is the principal cause of voltage drop.

Shunt compensation consists of inductors placed from each line to neutral and is used to reduce the shunt susceptance of the line.

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Recommended reading:

The fundamentals of steam power plants

9 power generating units grouped by prime mover you should know about

 



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How to make the right selection of a


Introduction to transducer

The accurate measurement of the voltage, current or other parameter of a power system is a prerequisite to any form of control, ranging from automatic closed-loop control to the recording of data for statistical purposes. Measurement of these parameters can be accomplished in a variety of ways, including the use of direct-reading instruments as well as electrical measuring transducers.

How to make the right selection of a digital transducer to perform power system measurements (photo credit: zillionelectric.com)

There are a wide range of measurement devices used to collect data and convert it into useful information for the operator. Generally, the devices are classified as to whether the measurements are to be used locally or remotely.

  • Local Information: by instruments or meters which (directly connected, or via a transducer), and measurement centres
  • Transmitted Data: by transducers
  • Remote Systems: by measurement centres, disturbance recorders or power quality recorders

Table of contents:

  1. General transducer characteristics
    1. Transducer Inputs
    2. Transducer Outputs
    3. Transducer Accuracy
  2. Digital Transducer Technology
  3. Analogue Transducer Technology
  4. Transducer Selection
    1. Current Transducers
    2. Voltage Transducers
    3. Frequency
    4. Phase Angle
    5. Power Quantities (Watts and Vars)
    6. Scaling
    7. Auxiliary Supplies

1. General transducer characteristics

Transducers produce an accurate d.c. analogue output, usually a current, which corresponds to the parameter being measured (the measurand). They provide electrical isolation by transformers, sometimes referred to as ‘Galvanic Isolation’, between the input and the output. This is primarily a safety feature, but also means that the cabling from the output terminals to any receiving equipment can be lightweight and have a lower insulation specification.

The advantages over discrete measuring instruments are as follows:

  1. Mounted close to the source of the measurement, reducing instrument transformer burdens and increasing safety through elimination of long wiring runs
  2. Ability to mount display equipment remote from the transducer
  3. Ability to use multiple display elements per transducer
  4. The burden on CTs/VTs is considerably less

Outputs from transducers may be used in many ways – from simple presentation of measured values for an operator, to being utilised by a network automation scheme to determine the control strategy. Transducers may have single or multiple inputs and/or outputs. The inputs, outputs and any auxiliary circuits will all be isolated from each other. There may be more than one input quantity and the measurand may be a function of one or more of them.

Whatever measurement transducer is being used, there will usually be a choice between discrete and modular types, the latter being plug-in units to a standard rack. The location and user-preferences will dictate the choice of transducer type.

Go back to Contents Table ↑

1.1 Transducer Inputs

The input of a transducer is often taken from transformers and these may be of many different types. Ideally, to obtain the best overall accuracy, metering-class instrument transformers should be used since the transformer errors will be added, albeit algebraically, to the transducer errors.

However, it is common to apply transducers to protection-class instrument transformers and that is why transducers are usually characterised to be able to withstand significant short-term overloads on their current inputs.

A typical specification for the current input circuits of a transducer suitable for connection to protection-class instrument transformers is to withstand:

  • 300% of full-load current continuously
  • 2500% for three seconds
  • 5000% for one second

The input impedance of any current input circuit will be kept as low as possible, and that for voltage inputs will be kept as high as possible. This reduces errors due to impedance mismatch.

The back side of the SCADA multifunctional transducer
Figure 1 – The back side of the SCADA multifunctional transducer

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1.2 Transducer Outputs

The output of a transducer is usually a current source. This means that, within the output voltage range (compliance voltage) of the transducer, additional display devices can be added without limit and without any need for adjustment of the transducer. The value of the compliance voltage determines the maximum loop impedance of the output circuit, so a high value of compliance voltage facilitates remote location of an indicating instrument.

Where the output loop is used for control purposes, appropriately rated Zener diodes are sometimes fitted across the terminals of each of the devices in the series loop to guard against the possibility of their internal circuitry becoming open circuit. This ensures that a faulty device in the loop does not cause complete failure of the output loop.

The constant current nature of the transducer output simply raises the voltage and continues to force the correct output signal round the loop.

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1.3 Transducer Accuracy

Accuracy is usually of prime importance, but in making comparisons, it should be noted that accuracy can be defined in several ways and may only apply under very closely defined conditions of use. The following attempts to clarify some of the more common terms and relate them to practical situations, using the terminology given in IEC 60688.

The accuracy of a transducer will be affected, to a greater or lesser extent, by many factors, known as ‘influence quantities’, over which the user has little, or no, control.

Table 1 – Overall product accuracy requirements for energy monitoring, metering for energy conservation and revenue purposes

Overall product accuracy requirements for energy monitoring, metering for energy conservation and revenue purposes
IEC61869-2 (tables 201 and 202) & IEC60044-1 (tables 11 and 12) – Overall product accuracy requirements for energy monitoring, metering for energy conservation and revenue purposes

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2. Digital transducer technology

Digital power system transducers make use of the same technology as that described for digital and numerical relays in this article. The analogue signals acquired from VTs and CTs are filtered to avoid aliasing, converted to digital form using A/D conversion, and then signal processing is carried out to extract the information required.

Sample rates of 64 samples/cycle or greater may be used, and the accuracy class is normally 0.2 or 0.5. Outputs may be both digital and analogue. The analogue outputs will be affected by the factors influencing accuracy as described above.

Digital outputs are typically in the form of a communications link, with RS232 or RS485 serial, and RJ45 Ethernet connections commonly available.

The response time may suffer compared to analogue transducers, depending on the rate at which values are transferred to the communications link and the delay in processing data at the receiving end. In fact, all of the influence quantities that affect a traditional analogue transducer also are present in a digital transducer in some form, but the errors resulting may be much less than in an analogue transducer and it may be more stable over a long period of time.

The advantages of a transducer using numerical technology are:

  1. Improved long-term stability
  2. More accurate r.m.s measurements
  3. Improved communications facilities
  4. Programmability of scaling
  5. Wider range of functions
  6. Reduced size
Fields of Application for Siemens's digital transducer type 'SICAM T'
Fields of Application for Siemens’s digital transducer type ‘SICAM T’

The improved long term stability reduces costs by extending the intervals between re-calibration. More accurate r.m.s measurements provide the user with data of improved accuracy, especially on supplies with significant harmonic content.

The improved communications facilities permit many transducers to share the same communications link, and each transducer to provide several measurements.

This leads to economy in interconnecting wiring and number of transducers used. Remote or local programmable scaling of the transducer permits scaling of the transducer in the field. The scaling can be changed to reflect changes in the network, or to be re-used elsewhere. Changes can be downloaded via the communications link, thus removing the need for a site visit.

It also minimizes the risk of the user specifying an incorrect scaling factor and having to return the transducer to the manufacturer for adjustment. Suppliers can keep a wider range of transducers suitable for a wide range of applications and inputs in stock, thus reducing delivery times.

Transducers are available with a much wider range of functions in one package, thus reducing space requirements in a switchboard. Functions available include harmonics up to the 31st, energy, and maximum demand information. The latter are useful for tariff negotiations.

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3. Analogue transducer technology

All analogue transducers have the following essential features:

  • An input circuit having impedance Zin
  • Isolation (no electrical connection) between input and output
  • An ideal current source generating an output current, I1, which is an accurate and linear function of Qin, the input quantity
  • A parallel output impedance, Zo. This represents the actual output impedance of the current source and shunts a small fraction, I2, of the ideal output
  • An output current, Io, equal to (I1 – I2)

These features are shown diagrammatically in Figure 22.1.

Schematic of an analogue transducer
Figure 22.1 – Schematic of an analogue transducer

Output ranges of 0-10mA, 0-20mA, and 4-20mA are common. Live zero (e.g. 4-20mA), suppressed zero (e.g. 0-10mA for 300-500kV) and linear inverse range (e.g. 10-0mA for 0-15kV) transducers normally require an auxiliary supply.

The dual-slope type has two linear sections to its output characteristic, for example, an output of 0-2mA for the first part of the input range, 0-8kV, and 2-10mA for the second part, 8-15kV.

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4. Transducer Selection

The selection of the correct transducer to perform a measurement function depends on many factors. These are detailed below.

4.1 Current Transducers

Current transducers are usually connected to the secondary of an instrument current transformer with a rated output of 1 or 5 amps. Mean-sensing and true r.m.s. types are available. If the waveform contains significant amounts of harmonics, a true r.m.s sensing type must be used for accurate measurement of the input.

They can be self-powered, except for the true r.m.s. types, or when a live zero output (for example 4-20mA) is required. They are not directional and, therefore, are unable to distinguish between ‘export’ and ‘import’ current.

To obtain a directional signal, a voltage input is also required.

Current transducer
Current transducer

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4.2 Voltage Transducers

Connection is usually to the secondary of an instrument voltage transformer but may be direct if the measured quantity is of sufficiently low voltage. The suppressed zero type is commonly used to provide an output for a specific range of input voltage where measurement of zero on the input quantity is not required.

The linear inverse type is often used as an aid to synchronising.

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4.3 Frequency

Accurate measurement of frequency is of vital importance to transmission system operators but not quite so important, perhaps, for the operator of a diesel generator set. Accuracy specifications of 0.1% and 0.01% are available, based on percent of centre scale frequency.

This means, for example that a device quoted as 0.1% and having a centre scale value of 50Hz will have a maximum error of +/- 50mHz under reference conditions.

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4.4 Phase Angle

Transducers for the measurement of phase angle are frequently used for the display of power factor. This is achieved by scaling the indicating instrument in a non-linear fashion, following the cosine law. For digital indicators and SCADA equipment, it is necessary for the receiving equipment to provide appropriate conversions to achieve the correct display of power factor.

Phase angle transducers are available with various input ranges. When the scaling is -180°…0°…180°, there is an ambiguous region, of about +/-2° at the extremes of the range. In this region, where the output is expected to be, for example, –10mA or +10mA, the output may jump sporadically from one of the full-scale values to the other.

Transducers are also available for the measurement of the angle between two input voltages. Some types of phase angle transducer use the zero crossing point of the input waveform to obtain the phase information and are thus prone to error if the input contains significant amounts of harmonics.

Calculating the power factor from the values of the outputs of a watt and a var transducer will give a true measurement in the presence of harmonics.

Hardware connectivity diagram for SCADA substation
Hardware connectivity diagram for SCADA substation

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4.5 Power Quantities

The measurement of active power (watts) and reactive power (vars) is generally not quite as simple as for the other quantities. More care needs to be taken with the selection of these types because of the variety of configurations.

It is essential to select the appropriate type for the system to be measured by taking into account factors such as system operating conditions (balanced or unbalanced load), the number of current and voltage connections available and whether the power flow is likely to be ‘import’, ‘export’, or both.

The range of the measurand will need to encompass all required possibilities of over-range under normal conditions so that the transducer and its indicating instrument, or other receiving equipment, is not used above the upper limit of its effective range. Figure 22.2 illustrates the connections to be used for the various types of measurement.

Connections for 3-phase watt/VAr transducers
Figure 22.2 – Connections for 3-phase watt/VAr transducers

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4.6 Scaling

The relationship of the output current to the value of the measurand is of vital importance and needs careful consideration. Any receiving equipment must, of course, be used within its rating but, if possible, some kind of standard should be established.

Example

As an example, examine the measurement of AC voltage. The primary system has a nominal value of 11kV and the transformer has a ratio of 11kV/110V. To specify the conversion coefficient for the voltage transducer to be 110V/10mA would not necessarily be the optimum. One of the objectives must be to have the capability of monitoring the voltage over a range of values so an upper limit must be selected – for instance +20%, or 132V. Using the original conversion coefficient, the maximum output of the transducer is required to be 12mA.

This is within the capability of most 0-10mA transducers, the majority of which can accommodate an over-range of 25%, but it does mean any associated analogue indicating instrument must have a sensitivity of 12mA.

However, the scale required on this instrument is now 0-13.2kV, which may lead to difficulty in drawing the scale in such a way as to make it readable (and conforms to the relevant standard). In this example, it would be more straightforward to establish the full-scale indication as 15kV and to make this equivalent to 10mA, thus making the specification of the display instrument much easier.

The transducer will have to be specified such that an input of 0-150V gives an output of 0-10mA. In the case of transducers with a 4-20mA output, great care is required in the output scaling, as there is no over-range capability. The 20mA output limit is a fixed one from a measurement point of view.

Such outputs are typically used as inputs to SCADA systems, and the SCADA system is normally programmed to assume that a current magnitude in excess of 20mA represents a transducer failure. In addition, a reading below 4mA also indicates a failure, usually an open circuit in the input connection.

Thus, using the above example, the output might be scaled so that 20mA represents 132V and hence the nominal 110V input results in an output of 16.67mA. A more convenient scaling might be to use 16mA as representing 110V, with 20mA output being equal to 137.5V (i.e. 25% over-range instead of the 20% required).

It would be incorrect to scale the transducer so that 110V input was represented by 20mA output, as the over-range capability required would not be available.

Similar considerations apply to current transducers and, with added complexity, to watt transducers, where the ratios of both the voltage and the current transformers must be taken into account. In this instance, the output will be related to the primary power of the system.

It should be noted that the input current corresponding to full-scale output may not be exactly equal to the secondary rating of the current transformer but this does not matter – the manufacturer will take this into account. Some of these difficulties do not need to be considered if the transducer is only feeding, for example, a SCADA outstation. Any receiving equipment that can be programmed to apply a scaling factor to each individual input can accommodate most input signal ranges.

The main consideration will be to ensure that the transducer is capable of providing a signal right up to the full-scale value of the input, that is, it does not saturate at the highest expected value of the measurand.

Recommended reading:

Voltage and current measurement in modern digital high voltage substations

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4.7 Auxiliary Supplies

Some transducers do not require any auxiliary supply. These are termed ‘self-powered’ transducers. Of those that do need a separate supply, the majority have a biased, or live zero output, such as 4-20mA. This is because a non-zero output cannot be obtained for zero input unless a separate supply is available.

Transducers that require an auxiliary supply are generally provided with a separate pair of terminals for the auxiliary circuit so that the user has the flexibility of connecting the auxiliary supply input to the measured voltage, or to a separate supply. However, some manufacturers have standardized their designs such that they appear to be of the self-powered type, but the auxiliary supply connection is actually internal.

For AC measuring transducers, the use of a DC auxiliary supply enables the transducer to be operated over a wider range of input. The range of auxiliary supply voltage over which a transducer can be operated is specified by the manufacturer. If the auxiliary voltage is derived from an input quantity, the range of measurement will be restricted to about +/-20% of the nominal auxiliary supply voltage.

This can give rise to problems when attempting to measure low values of the input quantity.

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Source: Alstom Grid



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Six differential stator-phase-fault


Phase faults and large fault currents

Generally, phase faults at generators rarely occur, but when they do, large fault currents can flow and make the mess. The best protection is differential (ANSI 87), and this type is recommended for all generators, except maybe for small units of 1 MVA and less. It’s important to note that this provides sensitive protection to phase faults, but may not provide ground fault protection, depending on the type of grounding used.

Stator phase-fault protection for generators
Stator phase-fault protection for generators (on photo: An classic generator in Central Electrique Ohm, an old power station in Belgium)

Let’s describe now the six most important differential stator phase-fault protection (87) for all size generators:

  1. Differential protection (87) for small kVA (MVA) generators
  2. Multi-CT differential protection (87) for all size generators
  3. High-impedance voltage differential protection for generators
  4. Direct-connected generator current differential example
  5. Phase protection for small generators that do not use differentials
  6. Unit generator current differential (87) example for phase protection

1. Differential protection (87) for small kVA (MVA) generators

The preferred method for small units is shown in Figure 1. The limitation is the ability to pass the two conductors through the window or opening of the CT. Typical opening diameters are about 4–8 in. However, where this is possible, high-sensitivity, high-speed protection is obtained, and CT performance does not have to be matched, for there is only one involved per phase.

The flux summation CT ratio (commonly 50:5) is independent of generator load current. Typical sensitivities in the order of 5 A primary current can be obtained. This provides protection for both phase- and ground-fault currents as long as the fault level for faults within the differential zone is greater than the sensitivity.

Differential protection for small generator units with flux summation current transformers and an instantaneous overcurrent (50 relay)
Figure 1 – Differential protection for small generator units with flux summation current transformers and an instantaneous overcurrent (50 relay)

This scheme does not provide protection to the connections from the flux summation CT to the generator breaker, unless the CT is on the bus side of the breaker and the generator neutral side leads are carried to that point. This is seldom practical, so other protection must be provided for this area between the flux summation CT and the breaker.

In general, this scheme (see Figure 1) is more sensitive as long as the generator CT ratio is greater than 150:5 to 200:5. If the flux summation CT is not applicable and differential protection is desired, the schemes of Figure 2c and Figure 2d can be used. See below.

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2. Multi-CT differential protection (87) for all size generators

This protection is widely used to provide fast and very sensitive protection to the generator and associated circuits. The 87 relays are connected to two sets of current transformers; one set in the neutral leads, the other in the line side.

For generators with associated breakers, the line-side CTs are usually associated with the breaker, as shown in Figure 2a and Figure 2b.

Direct-connected generator units (one or more) to a common system bus
Figure 2a – Direct-connected generator units (one or more) to a common system bus
Typical protection for a direct-connected generator
Figure 2b – Typical protection for a direct-connected generator. (*) Dotted relays are optional except 29/57 under- or overvoltage and 81 under- or overvoltage mandatory for non-utility generators connected to a utility; (#50) not always applicable.

For unit generators the line-side CTs are usually quite close to the generator, basically at the generator terminals. Typical connections for the three-phase units are shown in Figure 2c and 2d for both wye- and delta-connected generators.

Typical differential (87) connections for the protection of wye-connected generator
Figure 2c – Typical differential (87) connections for the protection of wye-connected generator

If current transformers are available at each end of the windings for the delta-connected generators of Figure 2d, the differential relays can be applied for winding protection. The connections would be similar to those shown in Figure 2c.

However, this would not provide protection for the junction points or the phase circuits that are within the protection zone (see Figure 2d).

Typical differential (87) connections for the protection of delta-connected generator
Figure 2d – Typical differential (87) connections for the protection of delta-connected generator

Usually, the differential CTs have the same ratio, and they should preferably be of the same type and manufacture to minimize mismatch errors for external faults. This is difficult for generators of Figure 2a and Figure 2b, where the CTs in the neutral are one type and those associated with the breaker are another type.

It is preferable not to connect any other equipment in the differential circuit and to keep the lead burden as low as possible.

Generally, the impedance of the restraint winding of differential relays is low. All this contributes to a totally low-burden and increased performance margins for the CTs.

The application recommendations permit the use of sensitive generator differential relays with low percentage characteristics, typically 10%–25% for the fixed percentage types and the equivalent or lower for the variable types.  Relay sensitivities (pickup current) are near 0.14–0.18 A for the 10% and variable percentage types and about 0.50 A for the 25% types. The operating time should be fast to open the breaker(s), remove the field, and initiate reduction of the prime-mover input.

Unfortunately, the flux in the machine continues to supply the fault for several seconds (about 8–16 sec), so instantaneous de-energization of generator faults is not possible. Problems with magnetizing inrush generally are not severe because the voltage on the machine is developed gradually, and the generator is carefully synchronized to the power system.

However, the differential relays should have good immunity to avoid incorrect operation on an external fault that significantly lowers the voltage, which recovers when the fault is cleared. This can cause a ‘‘recovery inrush’’. This is not applicable to those units that are subject to energizing a transformer or power system at full voltage (black start).

Cross-compound generators have two units, generally connected to a common power transformer. For these units a separate differential relay is applied for each generator unit connected (see Figure 2c above).

Split-winding generators, where the two winding halves are available with CTs in one of the halves (Figure 3), can be protected with two separate differentials.

Typical differential (87) connections for the protection of a split-winding generator
Figure 3 – Typical differential (87) connections for the protection of a split-winding generator

By comparing one winding half against the total, as shown, protection for shorted turns and open-circuited windings is possible. This is difficult or impossible for conventional relaying until the fault develops into the other phases or the ground. Where a 2:1 CT ratio is not available, auxiliary CTs can be used.

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3. High-impedance voltage differential protection for generators

The high-impedance voltage type of differential protection scheme can be applied as an alternative to the current differential type described. The relays are connected between phase and neutral leads of the paralleled CTs.

This protection scheme is widely used for bus protection and is described further below. The CT requirements are more or less critical. They should have identical characteristics, negligible leakage reactance, and fully distributed secondary windings.

More about bus protection:

The Basics of Electrical Bus Protections

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4. Direct-connected generator current differential example

A 20 MVA generator is connected to a 115 kV power system, as shown in Figure 4. The 87 differential relays are connected to the generator neutral
and circuit breaker CTs. On a 20 MVA base, the equivalent system reactance is 20/100(0.2) = 0.04 pu.

For this, in an internal three-phase fault at F, the total reactance to the fault is:

  • X1 = (0.32 × 0.14) / 0.46 = 0.097 pu
  • I30 = 1/0.097 = 10.27 pu at 20 MVA
  • I30 = 10.27 × 20,000/(√3 × 13.8) = 8593.5 A at 13.8 kV
  • Imax load = 20,000/(√3 × 13.8) = 836.74 A at 13.8 kV

Selecting 1000:5 CTs (Rc = 200) Imax load = 4.18 A secondary. With this CT ratio, I30 = 42.96 A, in the 87 relay-operating coil. This is many multiples of the typical pickup of about 0.4 A for positive and fast operation.

Example of an ungrounded generator connected to a utility through wye–delta transformer with a ground resistor to limit the ground fault to about 400 A at 13.8 kV
Figure 4 – Example of an ungrounded generator connected to a utility through wye–delta transformer with a ground resistor to limit the ground fault to about 400 A at 13.8 kV

If the three-phase fault occurred before the generator was synchronized to the power system,

  • I30 = 1/0.32 = 3.13 pu = 2614.8 A at 13.8 kV
  • I30 = 13.1 A through the 87 operating coil

Once again, multiples of pickup are needed for good operation. The transformer of Figure 1 is grounded on the generator side through a 19 Ω resistor. This limits the phase-to-ground faults to just over 400 A.

For an internal ground fault at F, I0g = 400/200 = 2.0 through the operating coil

With the 87 phase relays set to operate at 0.4 A, the solid ground fault of 2.0 A is five times the relay pickup. Thus, ground fault protection is provided, but should be supplemented with 50N/51N overcurrent relays connected in the grounded neutral.

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5. Phase protection for small generators that do not use differentials

Where small power sources are connected to a large system, protection for phase faults or reflection in the ac circuits of these small sources can be obtained from instantaneous overcurrent (50) or time–overcurrent (51) relays. These are connected in the interconnecting phases to operate on fault currents supplied by the large system.

Because these relays are non-directional, they must be coordinated with upstream devices for which the small generators can supply fault current.

This contribution may not exist for some power sources:

They usually exist only for a short time for induction generators (see next paragraph) or are relatively small for synchronous generators. In addition, the current supplied by synchronous generators will decrease with time, from subtransient, to transient, to synchronous, as illustrated in Figure 5a. Induction generators need external sources for excitation.

Guide illustrating the effects of rotating machine decrements on the symmetrical fault current
Figure 5 – Guide illustrating the effects of rotating machine decrements on the symmetrical fault current. (a) At generating stations, industrial plants with all local generation, no utility tie; (b) Induction motors are not considered as sources of fault current for protection purposes.

When a fault occurs and reduces the voltage, they generally provide a very short-time contribution to faults, as do induction motors (see Figure 5b). If they are islanded with other induction and synchronous machines, it is possible that the system can supply necessary excitation for the induction generator to continue to supply a fault.

Ground relays may also be used if the large system can supply ground fault current. This is dealt with further under the section on ground protection.

This protection is not possible to operate if the small generator is ungrounded and if it is not connected to the large system.

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6. Unit generator current differential (87) example for phase protection

Consider the unit-connected generator tied to a 345 kV power system as shown in Figure 6 below. For a three-phase fault on the 18 kV bus at F1, the positive-sequence network is shown and the total reactance to the fault is calculated as:

Total reactance to the fault

Typical example of a unit generator
Figure 6 – Typical example of a unit generator

These values are per unit on a 100 MVA base. The values in parentheses define current distribution on either side of the fault.

For a solid three-phase fault:

  • I1F1 = IaF1 = 1/0.064 = 15.70 pu,
  • I1 pu = 100.000/(√3×18) = 3,207.5 at 18 kV,
  • I1F1 = IaF1 = 15.7 × 3,207.5 = 50,357.3 A at 18 kV

The maximum load on the unit is:

Imax load = 160,000/(√3×10) = 5,132 at 18 kV

From this maximum load, a current transformer ratio of either 5500:5 or 6000:5 could be used. The lowest ratio is preferred for increased sensitivity, so suppose that 5500:5 (1100:1) is used. This gives a full-load secondary current of 5132/1100 or 4.67 A.

The three-phase secondary fault current is:

I1F = IaF1 = 50,357/1,100 = 45.78 A sec.

If the fault F1 is inside the 87 differential zone (see Figure 6) this 45.78 A would flow through the operating coil. This is many multiples of the differential relay pickup current for positive and fast operation.

For the external fault F1 as shown, the currents through the restraining windings of the differential relay would only be the contribution from the generator, which is:

I1F1gen = (50,357.3 × 0.485)/1,100 = 22.2 A sec.

This would be the internal and total fault current if a three-phase fault occurred before the units were synchronized to the 345 kV system. For these cases the fault current can be calculated alternatively as:

  • I1F1gen = 1.0/0.131 = 7.62 pu
  • I1F1gen = 7.62 × 3207.5 = 24,438.11 A at 18 kV,
  • I1F1gen = 24,438.1 / 1,100  =22.2 A sec.

Further reading:

Practical tips for the protection of generators and power transformers

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Source: Protective Relaying Principles and Applications by J. Lewis Blackburn and Thomas J. Domin



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AC and DC facilities in electrical station


Station services switchgear in power plants

In a power plant, the electrical station services (abbreviated to SS in the following) consist of all the DC facilities from 24 to 220 V and AC facilities up to about 20 kV for controlling and supplying power to the equipment needed to keep the plant running. Hence, these auxiliary services clearly play a vital role in assuring the plant’s reliable operation.

AC and DC facilities in electrical station services of major power plant types
AC and DC facilities in electrical station services of major power plant types

Close attention must therefore be paid to requirements affecting the particular plant and the safety considerations, such as the provision of backup systems.

Table of contents:

  1. Alternating current (AC) station services
  2. Direct current (DC) station services
  3. Station services in power plants
    1. Hydro power plants
    2. Diesel power plants
    3. Gas turbine / combined-cycle power plants
    4. Conventional steam thermal power plant
    5. Combined heat and power stations
  4. Automatic station service power transfer
    1. Switchgear configuration with two circuit breakers

1. Alternating current (AC) station services

The AC services for a generating plant unit consist essentially of the station service power transformer, in most cases a medium voltage distribution network, and low voltage distribution facilities. They may include a power transformer and the necessary distribution gear fed from a separate MV network for supplying general loads, i.e. not directly related to the generating unit, and possibly for starting the units and shutting them down.

Standby power supplies are dealt with in the below technical article.

Generators applicable to high reliability requirements of healthcare and other facilities

The basic SS arrangement in a so-called unit-type system for a power plant composed of separate units is shown in Figure 1, and the corresponding layout for a bus-type system in Figure 2.

The advantages of the unit-type configuration are that the ratings for the SS distribution facilities are lower, making it easier to cope with short-circuit currents and that the units are self-contained, so enhanced availability.

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Five actions to achieve excellent energy


Quite complex, but very possible…

Not all existing electrical installations lack energy efficiency, but most of them do. Especially if they were built 15-20 years ago and older. Although it is generally acknowledged that substantial energy savings are possible in most existing installations, the process of achieving these savings is more complicated than it may seem. So, what could we do about it? This article will try to explain the process.

Five actions to achieve excellent energy savings in old electrical installations
Five actions to achieve excellent energy savings in old electrical installations (photo credit: electronicspecifier.com)

Suggesting and implementing alternative lower consumption solutions (motors, high-efficiency transformers, energy compensation, low consumption lighting, etc.) and also installing regulation and automation systems (electrical control units, PLCs, intelligent management, etc.) are investments that have to be validated and justified by diagnostics based on relevant sets of readings requiring the necessary measuring apparatus (metering, instrumentation, recording of consumptions and events, etc.).

The “energy efficiency project” methodology must leave nothing to chance.

Table of contents:

  1. The diagnostic phase
    1. Descriptive summary
    2. Functional summary: load items and their distribution
  2. Collection of information and taking measurements
    1. Luxmeter
    2. Presence meter
    3. Temperature recorder or multichannel acquisition unit
    4. Wattmeter
    5. Recording analyser
  3. Processing the data, consideration and identification of possibilities and improvement
    1. Questioning phase
  4. Implementing the improvement project
    1. Possible actions
    2. A few common sense rules
    3. Recommendation and presentation of actions
    4. Checking and monitoring

1. The diagnostic phase

The initial process consists of attempting to understand how the electricity is consumed, irrespective of whether or not this is the only source of energy.

What are the largest functions? How is the electricity used?

If it is known exactly what the energy is used for, it may be possible to act at the source by making changes to the function itself. As a general rule, the preparatory phase of the project is based on work that is divided into two parts which are complementary but may sometimes be contradictory.

These parts are:

  1. Concrete, physical descriptive summary (the installation, the areas, the sources, the buildings, etc.) and
  2. Functional summary, which is often complex, as it is connected with human behaviour.

Its description must be intelligent, balanced and always prudent. We all forget to turn off a light sometimes. So while some types of behaviour may seem surprising, it is the cause we must investigate and not the consequence that must be pointed out.

1.1. Descriptive summary

The descriptive summary must first and foremost delineate and identify the main areas made up by the principal buildings (workshops, warehouses, storerooms, etc.) or main sectors of the entity in question which are intended on the whole for a main function: manufacturing, offices, warehouses, etc.

Ideally sources which give rise to energy metering should be superimposed over these areas, with for example a source item or better still a consumption history. Failing this, appropriate measuring apparatus must be available at least during the diagnostic phase.

The surface areas, number of floors, number of people present, and possibly other details such as the year of construction, and any element relating to the energy aspect (glazed areas, doors, structural components, etc.) must be specified in the descriptive summary.

Quantification of the changes in consumption at the site being examined
Figure 1 – Quantification of the changes in consumption at the site being examined

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Energy efficiency

Although it is right that heating and air conditioning account for a very large part of the energy consumption of buildings, in particular residential buildings (approximately 40% in Europe), other energy-consuming processes in the industrial field and also the commercial field may also be improved:

  • Motors,
  • Furnaces,
  • Electrolysis systems,
  • Lighting,
  • IT,
  • Refrigeration (in shops and warehouses),
  • Hot water production,
  • etc.

Some diagnostic studies have shown that energy consumption is hardly reduced at all during periods when premises are not occupied, even for long periods. And generally this is not due to non public spirited behaviour, but quite simply systems that were not designed from the outset to incorporate energy optimisation aspects.

All the activities in each area must be assessed in terms of electrical consumption. The main activity and secondary activities must be distinguished. The secondary activities may often be less secondary than they seem: for example a cafeteria that consumes more energy than the kitchens.

Distribution of the billed amount and consumption of the various buildings
Figure 2 – Distribution of the billed amount and consumption of the various buildings

The analysis of the energy company’s bills will give an overview of the energy consumption (active and reactive) and the share of the fixed items (standing charge and costs). In some cases, the customer also has access to a consumption history and can therefore ascertain the power consumption profile according to the time (measured in 10 min intervals) or even the season.

These two pieces of information will give an initial indication which will of course be general, but will already enable correlation with the operation of some high consumption items.

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1.2. Functional summary: load items and their distribution

Unlike the first step which involved the description, the second step of the preparatory phase will consist of designating the main functions or load items and relating to each of them the devices or applications involved in that item.

Of course this is not the simplest approach, because it will be necessary to examine all the applications with sufficient precision, but without getting lost in too much detail.

Taking the example of a large retail park, the lighting function (or load item) will be linked to numerous applications ranging from external car park lighting, to safety lighting, and including the lighting of shop windows, offices, corridors, shelves, storerooms, cloakrooms, etc. It can be seen immediately that the measurement of all the consumptions by all the applications will reveal the challenge.

Choices, sometimes arbitrary, must be made to select only high consumption applications or those which would a priori be wasteful.

A few preliminary measurements could be necessary at this stage in order to decide on the advantage of carrying out a more in-depth diagnosis of a particular function. The relative share of each of these load items must then be allocated to each of the previously defined main areas. Some load items may match one area fairly exactly, while for others the area identified may have numerous functions whose relative share must assessed.

This is usually the role of the power analysis prior to a project, but in the case of an existing installation, it is the measurement that will provide information on this exact share.

Identification of areas, applications, load items and relative shares
Figure 3 – Identification of areas, applications, load items and relative shares

The process shown in the example in the block diagram on the previous page can be used to determine the relative shares of each of the functions by area or by building. These shares must be related to the actual measured consumptions (see block diagram). It is thus possible to establish relationships between the applications and the main consumptions.

In the example described, it is for example important to understand why building B has a relative heating consumption share of 70% whereas building C, with an identical surface area, only has a 20% relative share.

Of course, numerous other questions must also be asked:

Question № 1 – Comparison of the actual energy consumptions in kWh.

Question № 2 – Understanding of why individual air conditioning units are installed in this building.

Question № 3 – Is the solar gain perhaps much higher in building C? This could explain the lower heating demand but, as a counterpart, the cooling requirement.

At this stage in the considerations, consultation of the consumptions according to the times of year could be revealing.

Question № 4 – Should better use be made of the solar gain, which is useful in winter but inconvenient in summer?

Individual air conditioning units are certainly not the right answer. Deflectors, awnings, a centralised air conditioning system or even changes to the hours during which the premises are occupied are all hypotheses that should be explored.

Question № 5 – The assumption that a large part of the heat is generated by the lighting (50% of the consumption of building C) must be precisely quantified.

If all these questions do not provide satisfactory answers, it may be necessary to look for them in the characteristics of the buildings.

Question № 6 – Is the insulation of building B adequate? Numerous causes can be investigated: aren’t there abnormally high losses in the actual functioning of building B?

The doors opening onto the loading bays are often open. It could be possible to consider asking users to close them, but if this has to be said ten times a day, the effectiveness of the measure is likely to be uncertain. Other solutions such as air curtains or automatic closing systems should therefore be considered.

The targeted identification of functions can be seen on this simple example, and their relative share in relation to the overall environment of the installation enables numerous questions to be asked, using a few figures (consumptions, monitoring, distribution, etc.). Some often have logical answers: building D consumes 80% of the cooling. It is a cold store and furthermore its specific consumption is limited (relative share 15%). It is accepted that it will not be subject to measurements in this initial diagnosis operation.

Although evidence may appear on simple reading of the available consumption figures, it must be remembered that many points will only appear when additional information is collected: operating cycles, human occupation, local climatology, characteristics of the buildings, etc. which must be cross-referenced with the measurements taken on-site.

The exact relative share of the functions/applications described in this diagram cannot generally be completed until after measurements have been taken.

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2. Collection of information and taking measurements

2.1. Luxmeter

The lighting on constant power light sources is measured using a luxmeter.  The lamp meter is a device that also has memory functions. It is installed in the immediate vicinity of each point of light to be evaluated. It has an optical sensor that records the periods during which the lighting is operational.

When using this, the power of the lighting equipment (assumed to be constant throughout the whole measurement period) must also be measured.

The specific energy consumptions can be ascertained by multiplying the power by the recorded durations.

Luxmeters for high-precision light measurement
Figure 4 – Luxmeters for high-precision light measurement (photo credit: Testo)

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2.2. Presence meter

The presence meter is a very compact standalone electronic recorder fitted with an infrared detection module. Each time someone enters the sensor’s detection area the event will be stored in the memory: detection start and end date and time.

This device provides precise information on the traffic and human presence in a given area.

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2.3. Temperature recorder or multichannel acquisition unit

Small standalone thermometers are available that carry out repetitive measurements (for example, every two minutes) and calculate the average per period. The values are stored in the memory.

More sophisticated devices such as measurement control units can acquire a wide variety of data, including the temperature, over hundreds of points. Their installation and connection are more complicated, but some can now be interfaced on a local area network, Internet or even the smartphone.

Data logger that measures and transmits temperature and relative humidity data wirelessly to mobile devices via Bluetooth Low Energy
Figure 5 – Data logger that measures and transmits temperature and relative humidity data wirelessly to mobile devices via Bluetooth (photo credit: onsetcomp.com)

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2.4. Wattmeter

This device is used for measuring power. Current digital models can be used to access all values: P, Q, S, U; I, cos ϕ, PF (power factor), etc., and even harmonic and frequency values. Some even carry out direct energy calculations by integrating the measurement time.

These are referred to as power analysers.

The WT500 Power Analyzer excels at single- and three-phase power measurements
Figure 6 – The WT500 Power Analyzer excels at single- and three-phase power measurements (photo credit: Yokogawa Electric Corporation)

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2.5. Recording analyser

This performs some or all of the functions of the power analyser but can record values measured over long periods.

It produces histograms which are very useful since, as well as giving details of instantaneous values, they can be used to establish precise relationships between consumption and events.

Recording analyser
Figure 7 – Recording analyser

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3. Processing the data, consideration and identification of possibilities and improvement

The collection of large quantities of measurements may cause dispersion and considerable difficulty of interpretation. Paradoxically the huge data acquisition capacities of today’s devices mean that it is not always easy to sort out what is relevant and adequate.

The analysis must be carried out with clearly defined objectives for presentation of the results in such a way that they are easy to understand and compare.

For lighting, power per unit of surface area could be considered (see example), or daytime/night-time ratio. Different buildings could also be compared on this basis.

Table 1 – Example of analysis for lighting

Areas in building C Specific power during the day (W/m²) Specific power during the night (W/m²)
Assembly workshop 30 0
Corridors and staircases 15 5
Cloakrooms 7 0
Office on 1st floor 22 15
IT 40 40
Laboratory 25 10
Offices on 2nd floor 28 0
Basement warehouse 62 50
Access to the outside 2 2

The presentation of consumption according to periods of occupation is often very useful and could be a quick source of savings. In other cases, such as heating, a seasonal profile would be useful for comparing potential alternative resources such as solar energy.

Without going into detail in this table, several striking anachronisms can be quickly seen:

  1. Areas whose consumptions are very different while their theoretical requirements are identical,
  2. Areas that consume a great deal of energy for lighting while there are almost no humans present, and
  3. Areas where lights are not switched off at night when there is no reason for them to be kept on.

Apart from the potential savings, this type of presentation also confirms certain shortcomings. The external entry lighting, apart from operating in full daylight, also has the drawback of being ineffective. The very low power allotted to it confirms this.

It can be quickly seen that while making large savings on some items, it is also possible to make small outlays on others, leading to a significant improvement in the quality of service. Processing the data and the way the analysis report is presented are essential factors.

There are many possible interpretations of the results. The ability to organise the project and its chances of success will depend on selecting the correct interpretation.

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3.1 Questioning phase

Four essential questions to be asked:

  1. Is it justified for it to operate in this time slot?
  2. Is there an alternative solution that uses less energy?
  3. Is it absolutely essential?
  4. Is it possible to change the opening times?

One may imagine that it would therefore be possible to fulfil the same requirements with much less energy, and with a lower power demand. This very innovative approach has already been successfully applied to other types of buildings.

The consideration and questioning phase, which must lead to the examination of existing information, is essential.

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4. Implementing the improvement project

Following on logically from the diagnostic phase, the implementation phase will be based on the analysis report whose relevance and readability will have a significant influence on the decisions that are taken on actions.

The report must contain, in addition to a simplified description and block diagram of the installations, an outline of the energy analysis resulting from the measurements taken and the analysis of the consumption, and the identification of possible sources of savings.

Download an example of building energy monitoring and analysis report:

Download PDF

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4.1. Possible actions

At this stage, the decision can be taken to either do nothing or to undertake improvement work. There are often as many possibilities for improvement as there is information collected, to such a point that there is a real risk of trying undertake too many things at once, just as there is a risk of confusion over the expected effectiveness of an action.

It is therefore advisable to give an overall picture of the achievable improvement by subject and the associated cost involved.

Table 2 – Example of presentation

Possible actions Saving (1) Cost (2)
Raising staff awareness 1 to 3% Low 1,000 €
Changes to opening times 2 to 6% Low 1,500 €
Optimisation of operating modes 5% Negligible
Improvement of regulation 5 to 12% Average 15,000 €
High efficiency receivers and applications (motors, furnaces, etc.) 15 to 20% High 40,000 €
Changing heating boilers 8 to 15% High 180,000 €
Drawing up a lighting plan 10 to 20% Not costed (totally separate project)
Energy management (measurement, management, forecasting, purchase, etc.) 10 to 15% Average 10,000 €
Improvement of electrical quality (power factor, harmonics) 2% Average 8,000 €

(1) In comparison with a reference consumption which is to be specified (for example, average over the last 3 years)
(2) Low, medium or high, or if possible a more precise value

Decisions can then be taken on various actions. They must be connected with a reference subject. Plainly, low cost operations should be undertaken quickly, even if the resulting savings are small.

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4.2 A few common sense rules

Apart from talking about new or renewable sources, positive energy or fantastic efficiency levels, we must not forget that saving means first and foremost not losing.

The “war on waste” must go on all year round…

  1. Putting an end to unnecessary consumption: too much heating or lighting, poor insulation, etc.
  2. Finding and correcting malfunctions: poor regulation, over-ventilation, inappropriate cycles, etc.
  3. Identifying unsuspected consumption: keeping an eye on devices and also permanent supplies of certain receivers (telephony, IT, etc.), UPS, etc.
  4. Only operating equipment when needed: lowering or turning off heating during periods when premises are not occupied, management and control of lighting, etc.
  5. Replacing antiquated equipment with modern, more economical devices: even if this involves going down a more costly route, as it is generally the most profitable.

    Heating technologies, whatever the energy source, have progressed a great deal. High-efficiency motors provide significant operational savings. The latest generation lighting systems provide better lighting and cost less.

  6. Making existing equipment more cost-effective: some processes can for example be used better in order to reduce their operating times.

Why is electric motor efficiency so important?

Here ABB explains the importance of high motor efficiency and MEPS (Minimum Energy Performance Standards), which sets the mandatory minimum efficiency levels for electric motors.

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4.3. Recommendation and presentation of actions

The recommended actions should be presented with a precise description of the application in question and the reference subject as just mentioned, supporting an energy cost justification based on the measurement phase, and proposing a replacement or improvement solution. The investment cost, and if required the maintenance cost, together with the resulting potential energy savings and cost savings must be presented in the form of a financial analysis with a cost-benefit calculation.

If the benefits and savings are identified, specific conditions for success may be specified. These may be for example:

Information on advantages in terms of efficiency, emission of greenhouse gases, and actual cost according to life cycle, will lead to a better understanding of the challenges of the envisaged action.

The recommended actions can  be presented together with the diagnostic report, but as a general rule it will be preferable to keep the two phases (diagnostic and improvement project) separate, as they will require different skills.

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5. Checking and monitoring

Having implemented the recommended actions, the effectiveness of the result can only be guaranteed if it is measured and checked. This is a prerequisite for contractual obligations.

On small installations, measurement devices can be simple (index meters) and readings can be taken manually, but as soon as the size or number of consumption points increase, full energy management systems combining measurement and management are more suitable.

These use appropriate computer software which makes it possible to directly establish load profiles, consumption curves and carry out any required processing.

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Source: Power balance and the choice of power supply solutions by Legrand



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The art of designing the auxiliary system


Auxiliary system design

Power plant auxiliary system is usually pretty complicated and consists of dozen of motors, transformers, capacitor banks, variable frequency drives, PLCs, and other electrical devices. Therefore, protection relaying cannot be simple, and it requires special attention for each component of a power and control system as well as coordination between them.

The art of designing the auxiliary system of a power plant
The art of designing the auxiliary system of a power plant

This technical article will shed some light on how an auxiliary system should be designed in order to sustain the main production facilities in power plants. Special attention is given to the protection coordination of motors, transformers, and other devices from the point of view of the normal and emergency operation of the entire plant.

Faulted electrical equipment MUST be removed from service as fast as possible. For many electrical faults or abnormal events within the plant this may require that the generator be removed from the system, the excitation system tripped, the turbine valves closed and the boiler fires extinguished. Often this is not acceptable.

However, it is necessary that vital services such as bearing oil pumps, instrument air compressors, exhaust and purging fans, etc. be maintained even though the unit has been tripped and is in the process of being shut down.

In addition, the auxiliary system must be configured to allow the unit to return to service as soon as possible.

Table of contents:

Auxiliary system of a unit-connected generator

A portion of a typical auxiliary system of a unit-connected generator is shown in Figure 1 below.

The 4 kV auxiliary bus is fed directly from the 20 kV generator leads or from the startup transformer and is the source for the major motors. As unit sizes increase, the auxiliary load increases proportionately, requiring higher rated transformers and higher rated, higher voltage motors. This has resulted in higher bus voltages, such as 6.9 kV and 13 kV.

Phase fault currents also increased, requiring switchgear with higher interrupting capacity. In sizing the switchgear there are two contradictory factors that must be considered. The impedance of standard transformers increases as their ratings increase.

Since the normal and short-circuit currents are also increasing, there is a greater voltage drop between the auxiliary bus and the motor.

Single line diagram of a typical power plant auxiliary system
Figure 1 – Single line diagram of a typical power plant auxiliary system with unit-connected generator

Normal design practice is to maintain at least 85 % voltage at the motor terminals during motor starting. If the standard transformer impedance is specified to be at a lower value to reduce the voltage drop and maintain the 85 % voltage criterion, the interrupting current will increase requiring larger rated switchgear

If the transformer impedance is raised to reduce the fault current, and hence the interrupting capacity requirement of the switchgear, the voltage drop will be too high.

The art of designing the auxiliary system must take all of these factors into account. Transformers can be specified with special impedances at a greater cost. The auxiliary system can be designed with several bus sections thus reducing the transformer rating for each section.

Current-limiting reactors can be used either as separate devices or incorporated in the switchgear.

In addition to the 4 kV (or higher) bus, a lower voltage auxiliary bus system is used to feed the dozens or hundreds of smaller motors, heating and lighting loads that are present in the plant. The nominal voltage rating of this lower voltage bus system can be 600 or 240 V.

The lower voltage buses are energized from the higher voltage bus as shown in Figure 1.

Automatic throw-over schemes between the several bus sections or between the generator step-up (GSU) and startup transformer are used in the event of a 4 kV bus fault or failure of a 20 kV/4 kV or 4 kV/600 V transformer. In addition, manual throw-over provides flexibility for maintenance without removing the generator from service.

The circuit breakers used on the lower voltage buses are included in the metal-enclosed switchgear and are covered in ANSI standards C37.20-1 and C37.20-3. They may not be draw-out type necessarily, don’t have CTs and may be mounted in motor control centers.

Circuit breakers may be air type or molded case breakers with limited interrupting capacity. Protection is provided by series trip coils or thermal elements.

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Which type of circuit breaker?

There are many circuit breaker designs depending upon the particular application:

  1. Oil circuit breakers
  2. Air circuit breakers
  3. Vacuum circuit breakers
  4. Sulfur hexafluoride (SF6) circuit breakers

Vacuum circuit breakers extinguish the arc in a gap of less than 13 mm (0.5 in) because there are no constituents in the vacuum that can be ionized to support the arc. Sulfur hexafluoride (SF6) circuit breakers extinguish the arc using one of two methods: the puffer design blows the arc out with a small amount of gas blasted in a restricted arc space; the rotating arc design uses the electromagnetic effect to rotate the arc through SF6 that cools and extinguishes it.

Nowadays, vacuum and SF6 circuit breakers are more commonly used. More about which one and where to apply, you can learn here. These circuit breakers are mainly drawout type, allowing the breaker to be removed for maintenance.

ABB UniGear ZS1 vacuum circuit breakers (VCB)
Figure 2 – ABB UniGear ZS1 vacuum circuit breakers (VCB) – photo credit: slaters-electricals.com

Medium voltage draw-out vacuum circuit breaker, type VD4
Figure 3 – Medium voltage draw-out vacuum circuit breaker, type VD4 – photo credit: slaters-electricals.com

Buses rated above 2400 V use metal-clad switchgear as defined in ANSI standard C37.20-2. The switchgear compartment contains the CTs, auxiliary contacts and, usually, the relays and meters.

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Phase fault protection (51)

The phase overcurrent relays (51A and 51B) on the secondary of the unit auxiliary and startup transformers provide bus protection and backup relaying for individual motor protection and switchgear.

Figure 1 indicates the general arrangement of the buses and loads and shows the protection of the 2000 hp motor and the 7500 hp motor.

Ideally, the backup overcurrent relays 51A and 51B should have pickup settings greater than the highest motor protection relay, and time delays longer than the longest starting time. These settings may be so high, or the times so long, that the protection is not acceptable and modifications or compromises are required as discussed below.

If the relays are also the primary bus protective relays, the settings may be so high that there may not be enough bus fault current to provide sufficient margin to ensure pickup for the minimum bus fault.

Phase overcurrent relays (51A and 51B) on the secondary of the unit auxiliary and startup transformers
Figure 4 – Phase overcurrent relays (51A and 51B) on the secondary of the unit auxiliary and startup transformers as a bus protection and backup relaying for individual motor protection and switchgear

Even if coordination is theoretically possible, the required time delay may be too long to be acceptable. Some compromises are possible. Since the largest motors will probably have differential protection, the backup function could consider coordinating with the overcurrent relays of the smaller motors with an associated reduction in pickup.

Assuming that the differential relays are always operative, coordination with the larger motors is not a problem since the differential protection is instantaneous. Coordination would be lost if the differential relays fail to clear a fault and the time-delay overcurrent relays must do it. This is usually an acceptable risk.

A bus differential relay could be used to provide primary protection and the overcurrent relays provide backup protection for motor relay or switchgear failures. The time delay may then be acceptable. The pickup setting must still recognize the magnitude of starting current of the largest motor.

If it cannot be set above this value, an interlock must be provided which will block the backup relay.

Overcurrent backup and bus differential protection scheme
Figure 5 – Overcurrent backup and bus differential protection scheme

The overcurrent backup relay will see the total current supplied to the bus, whereas the differential relay only sees the difference between supply current and load current as discussed previously. The relay settings for overcurrent backup protections are somewhat difficult and usually employ an instantaneous and timed component.

After all, the objective is that breakers X and Y should clear the fault before the backup protection operates to trip the main supply breaker S.

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Never underestimate ground fault protection

The importance of ground fault protection cannot be overemphasized. Ground is considered to be involved in 75–85 % of all faults. In addition, phase overcurrent may often reflect a temporary process overloading, while ground current is almost invariably an indication of a fault.

Auxiliary systems may be either delta- or wye-connected. A delta system is normally operated ungrounded and is allowed to remain in service when the first ground indication appears. It is generally assumed that the first ground can be isolated and corrected before a second ground occurs.

It is not uncommon for systems of 600 V and less to be delta-connected. Medium-voltage systems (5 kV to 15 kV) are generally operated in wye, with a neutral resistor to limit the ground current to some definite value.

The resistor has a time-related capability, e.g. 10 s, at the maximum ground current and it is a function of the ground protective system to remove all faults within this time constraint.

2.0 Ω neutral resistors in the auxiliary and startup transformers
Figure 6 – 2.0 Ω neutral resistors in the auxiliary and startup transformers

In Figure 6, ground faults on the 4 kV system are limited by the 2.0 Ω neutral resistors in the auxiliary and startup transformers. The magnitude of the maximum fault current is the lineto-ground voltage divided by the 2.0 Ω resistor. The nominal voltage of the bus is 4 kV but its normal operating voltage is 4160 V.

Therefore, the maximum ground current is 4160/(√3 × 2) or 1200 A.

Coordination must, of course, begin at the load. If the motor ground overcurrent protection is provided by the toroidal CT shown in Figure 7 there is no coordination problem.

Current transformers in relay protection applications
Figure 7 – Current transformers in relay protection applications (photo credit: merko.ee)

These can have a ratio of 50:5 resulting in a relay current of 120 A. Set an instantaneous relay at 5.0 A. If a residual ground relay is used as shown in Figure 8, the maximum ground fault through the CTs on breakers A and B is 1200/600 = 2.0 A. Set the time-delay ground overcurrent relays at 0.5 A and 15–30 cycles.

The motor relays trip the associated feeder breaker, 51A and 51B trip the 4 kV main breakers and the neutral relays 51N trip their associated primary breakers.

Residually connected ground relay
Figure 8 – Residually connected ground relay

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Bus transfer schemes (alternative source)

It is common practice to provide a bus transfer scheme to transfer the auxiliary bus to an alternative source in the event of the loss of the primary source. In power plants, the purpose of this alternative source is not to maintain normal operation but to provide a startup source, to act as a spare in the event an auxiliary transformer fails and to provide for orderly and safe shutdown.

In industrial plants, the alternative source might have a different purpose, such as to provide flexibility in production or supply some facilities from the utility and others from a local generator.

The transfer scheme must consider several factors. A manual, live transfer is performed by the operator while both the normal and startup sources are still energized. If the two sources can be out of synchronism, it will be necessary to include synchronizing equipment.

Some schemes monitor this residual voltage and allow closing to the alternative source only after this voltage has been significantly reduced.

A typical arrangement of unit and station switchboards, with unit to station bus transfer scheme
Figure 9 – A typical unit to station switchboard bus transfer scheme

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Generator breaker (needed or not?)

Figure 10 shows a generator breaker as an alternative facility. This is common for generators that are connected to a common bus, such as in a hydro plant. With the advent of the unit system, however, this configuration has not been used as often. The unit system requires that the boiler, turbine, generator and GSU transformer be operated as a single entity and the loss of any one element requires that all of them be removed from service.

The generator breaker is then unnecessary. In addition, as the unit sizes increased, the interrupting capability of a generator breaker became technically difficult. A 1300 MW generator can contribute as much as 100 000 A to a fault at the generator voltage level, e.g. on the bus feeding the auxiliary transformers.

Not only is such a breaker extremely costly, it must be placed between the generator and the step-up transformer, which adds considerable length to the building. This introduces costs to every segment of the construction and installation.

Generator breaker as an alternative facility
Figure 10 – Generator breaker as an alternative facility

Nevertheless, the generator breaker has can be extremely useful. Its most important advantage is the fact that, for a fault on the generator or auxiliary buses, without a generator breaker to remove the generator contribution from the fault, the generator will continue to feed the fault until the generator field decays. This can take as much as 7–10 s.

During this time the energy in the fault will result in extensive physical damage to all of the connected equipment and greatly increases the possibility of fire.

Referring to Figure 1, without a generator breaker, startup is accomplished by energizing the auxiliary buses through the 800 kV breaker F, the startup transformer and 4 kV breaker B. Synchronizing is done through 800 kV breaker E. In the event of a unit trip, the unit is removed from the system by opening breaker E and the auxiliary bus is transferred to the startup transformer by opening 4 kV breaker A and closing breaker B. Breaker F is operated normally closed.

If the startup transformer is connected to some other system, then breaker B must be closed with synchronizing relays. If a generator breaker is provided, at startup the generator breaker is open and the auxiliary buses are fed through the GSU transformer and 4 kV breaker A.

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Sources:

  • Power System Relaying by Stanley H. Horowitz, Arun G. Phadke (purchase the hardcover from Amazon)
  • Science and Reactor Fundamentals – Electrical | CNSC Technical Training Group
  • Switchgears book by BHEL – Bharat Heavy Electricals Limited



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IEC and NEMA/IEEE ratings of current


Metering and protection purpose

First, let’s remind ourselves of the basics in a few sentences. That is something you must know. A current transformer (CT) is designed to produce a secondary current which is accurately proportional to the primary current. It consists of a single primary winding, which an external busbar or cable runs through, or it can have a single primary bar, brought out to two ends for termination.

IEC and NEMA ratings of current transformers (CTs) for a medium voltage switchgear
IEC and NEMA ratings of current transformers (CTs) for a medium voltage switchgear (photo credit: Energie Technik Becker GmbH)

A medium voltage current transformer can have up to three independent secondary winding sets. The entire current transformer assembly is encapsulated in resin, inside an insulated casing. Current transformers are used for metering or protection purposes.

The accuracy class and size depends on the individual application – for example, revenue metering would use high accuracy metering CTs.

Just to note, it’s very important to never leave the secondary winding of a CT open circuit. This creates extremely high voltages which pose a real danger to personnel.

Ok, let’s get on the IEC and later NEMA ratings of a current transformer. Some rating explanations have exercises and real examples, which I hope it will help for better understanding.

  1. IEC  ratings of current transformer
    1. Rated primary current
    2. Rated secondary current: Isr
    3. Transformer ratio: Kn
    4. Rated thermal short-time withstand current: Ith (kA)
    5. Overcurrent coefficient: Ksi
    6. Rated primary circuit voltage: Up (kV)
    7. Rated frequency
    8. Rated real output power (VA)
      1. Exercises
    9. Metering class CT
    10. Protection class CT
      1. Example
    11. Selection of current transformers
      1. Exercise to select appropriate CTs
        1. Exercise #1
        2. Exercise #2
        3. Exercise #3
  2. NEMA/IEEE ratings of current transformer
    1. Accuracy class
    2. Class rating
    3. Burden
    4. Examples

1. IEC Ratings

1.1 Rated primary current: Ipr (A)

The primary current rating of a CT must be greater than the expected maximum operating current it is monitoring.

Metering CT’s primary current rating should not exceed 1.5 times the maximum operating current. Protection CT’s primary current rating needs to be chosen so that the protection pick-up level is attained during a fault.

Standard values for Ipr are: 10, 12.5, 15, 20, 25, 30, 40, 50, 60, 75 A, and decimal multiples of these values (source: IEC 60044-1)

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1.2 Rated secondary current: Isr

The secondary current rating of a CT is either 1 A or 5 A. CTs with a 5 A secondary rating are becoming less common as more CT driven equipment becomes digital. For long secondary cable runs, CTs with 1 A secondary windings can minimize the transformer and secondary cable size.

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1.3 Transformer ratio: Kn

This is the ratio of secondary to primary winding turns: Kn = Ns/Np = Ipr/Isr

Current transformer nameplate
Figure 1 – Current transformer nameplate

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1.4 Rated thermal short-time withstand current: Ith (kA)

This is the highest level of rms primary fault current which the CT can endure, both thermally and dynamically, for 1 second without damage. When used in a medium voltage enclosure, the Ith rating should match the short-time withstand rating of the entire switchgear.

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1.5 Overcurrent coefficient: Ksi

This is the ratio of a CT’s short-time withstand current rating to its primary current rating:

Ksi = Ith/Ipr

This coefficient indicates how difficult it would be to manufacture a CT. A higher coefficient means a physically larger CT, which is more difficult to manufacture.

  • If Ksi < 100 it’s easy to manufacture
  • If Ksi 100 ~ 500 it’s difficult to manufacture, with certain limitations
  • If Ksi > 500 it’s  extremely difficult to manufacture

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1.6 Rated primary circuit voltage: Up (kV)

The primary circuit voltage rating indicates the level on insulation provided by the CT. If a ring type CT is installed around a cable or bushing, the insulation level can be provided by the cable or bushing.

Rated primary voltage
Upr (kV)
Suitable operation range
U (kV)
Power frequency withstand voltage
(kV) rms for 1 minute
Lightning impulse withstand voltage
(kV) peak, 1.2/50μs
7.2 33-7.2 20 60
12 6-12 28 75
17.5 10-17.5 38 95
24 12-24 50 125
36 20-36 70 170

Source: IEC 62271-1

1.7 Rated frequency: fr (Hz)

This rating must match the system’s operating frequency. Standard frequencies are 50 Hz and 60 Hz. It’s very important to be cautios, because a 50 Hz CT can be used on a 60 Hz system, but a 60 Hz CT cannot be used on a 50 Hz system.

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1.8 Rated real output power (VA)

The maximum power a CT secondary can deliver, to guarantee its accuracy and performance. The total sum VA (including cable, connectors and load) must not exceed the rated real output power of the CT. Standard values are: 1, 2.5, 5, 10, 15 VA.

Cable burden can be calculated the following way: VAcable = k × L/S, where:

  • k = 0.44 for 5 A secondary, = 0.0176 for 1 A secondary
  • L = total feed/return length of cable (m)
  • S = cross sectional area of copper cable (mm2)

Metering instrument burden:

  • Metering instrument (digital) = 1 VA (approx.)
  • Metering instrument (electromagnetic or induction) = 3 VA (approx.)
  • Transducer (self powered) = 3 VA (approx.)

Protection instrument burden:

  • Protection instrument (digital) = 1 VA (approx.)
  • Protection instrument (electromagnetic overcurrent) = 3-10 VA (approx.)
Medium voltage current transformers
Figure 2 – Medium voltage current transformers

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1.8.1 Exercises

Exercise #1 – A CT with a 1 A secondary is connected to an electromagnetic ammeter located 10 m away, using 2.5 mm2 copper cable.

Calculate the minimum required VA rating of the CT.

  • VAcable = k × L/S = 0.0176 × 20/2.5 = 0.14 VA
  • VAammeter = 3 VA
  • VAtotal = 0.14 + 3 = 3.14 VA

The total burden is 3.14 VA. Use a 5 VA CT.

Exercise #2 – A CT with a 5 A secondary is connected to a digital protection relay located 2 m away, using 1.5 mm2 copper cable.

Calculate the minimum required VA rating of the CT.

  • VAcable = k × L/S = 0.44 × 4/1.5 = 1.17 VA
  • VAammeter = 1 VA
  • VAtotal = 1.17 + 1 = 2.17 VA

The total burden is 2.17 VA. Use a 2.5 VA CT.

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1.9 Metering class

A metering class indicates the accuracy of the CT secondary current at 5 to 125% of rated primary current. Above this level, the CT starts to saturate and the secondary current is clipped to protect the inputs of a connected metering instrument.

  • General metering CT would use a metering class CL 0.5 – 1.0
  • Revenue metering CT would use a metering class CL 0.2 – 0.5
Operating range for metering class current transformer
Figure 3 – Operating range for metering class current transformer

Where:

  1. Saturation
  2. Linear operating range, at accuracy class tolerance

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1.10 Protection class CT

A protection class CT provides a linear transformation of the primary to secondary current at high overload levels. This characteristic makes them suitable for use with overcurrent protection relays.

A relay trip setting is normally 10~15 times the maximum load current and this level should fall on the linear part of the CT secondary current curve. If a CT saturates before the relay trip level is reached, the fault will remain undetected, leading to equipment damage and serious danger to personnel.

The most commonly used protection class is a 5PX, where X is the accuracy limit factor (ALF) or multiplication factor of the rated primary current. The secondary current is +/-1% accurate at rated primary current and +/-5% accurate at X times rated primary current.

Typical protection class CT ratings are 5P10, 5P15, 5P20.

Operating range for protection class current transformer
Figure 4 – Operating range for protection class current transformer

Where:

  1. Saturation
  2. Linear operating range, at accuracy class tolerance
  3. Ideal protection setting trip zone 50%~100% ALF

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1.10.1 Example

A 200/1 A CT has a protection class rating of 5P15. The secondary current is guaranteed to be linear up to 15 times the rated primary current. The secondary current will be 1 A (+/-1%) at 200 A primary current and 15 A (+/-5%) at 3000 A primary current.

For guaranteed operation, any overcurrent trip setting should be between 7.5 ~ 15 A secondary current.

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1.11 Selection of current transformers

The main considerations for selecting a CT are the primary and secondary current ratio, real output power rating (VA) and accuracy class. Secondary selection considerations are rated primary voltage, frequency and thermal short-time withstand current.

1.11.1 Primary and secondary current ratio

Rated primary current: Ipr (A)

Source Rated primary current Ipr (A)
Incomer from transformer Ipr ≥ 1.0-1.25 of nominal source current
Feeder to transformer Ipr ≥ 1.0-1.25 of transformer’s rated primary current
Feeder to motor Ipr ≥ 1.0-1.5 of motor full load current
Feeder to capacitor bank Ipr ≥ 1.3-1.5 of nominal capacitor current

Rated secondary current: Isr (A)

  • Use 1 A and 5 A for local installation
  • Use 1 A for remote installation

1.11.2 Real output power (VA)

The real output rating of the CT must be the next highest nominal size above the expected total burden on the CT secondary. Total burden is the sum of output cable, connectors and instruments.

1.11.3 Class type

Use a metering class CT for metering and indication. A higher class CT gives greater accuracy between the primary and secondary currents.

Use a 5PX protection class CT for current based protection relay inputs. The ALF must be selected so that the relay trip point lies on the linear part of the secondary current curve, between 50% and 100% of the ALF.

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1.11.4 Exercise

Select appropriate CTs for the following transformer incomer and feeder circuits.

Example transformer incomer and feeder for selection of appropriate CTs
Figure 5 – Example transformer incomer and feeder for selection of appropriate CTs

Where:

1. Transformer Incomer:

2.Transformer Feeder:

  • MV/LV transformer (TXR2): 2 MVA, 11/0.4 kV, 5% Z
  • Instantaneous overcurrent trip setting = 10 × In for digital protection relay (OC2) driven off CT2

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Exercise 1 – Metering CT1-1 for transformer incomer circuit:

Step 1 – Calculate transformer TXR1 nominal secondary current: In (A)

  • In = S/(√3 × U) = 5000/(√3 × 11) = 262 A
  • The secondary current for TXR1 is 262 A

Step 2 – Calculated max. expected short circuit current at CT1 installation: Isc (A)

  • Ignoring any power cable or busbar impedances:
  • Isc = In × 100/Z = 262 × 100/10 = 2620 A
  • The maximum expected short circuit current at CT1 is 2620 A

Step 3 – Select metering CT1-1 ratings:

  • Primary rated current: Ipr = (1.0-1.25) × In = (1.0-1.25) × 262 A
    Use a rating of 300 A
  • Secondary rated current: Isr
    Use a rating of 1 A
  • Short-time withstand rating: Ith ≥ Isc
    Use a rating of 10 kA
  • Primary circuit voltage: Up ≥ U
    Use a rating of 12 kV
  • Real output power: Typically > 3 VA for electromagnetic type meter
    Use 5 VA (this allows 2 VA for cable burden, etc.)
  • Accuracy Class
    Use Class 1.0 (common class for general metering)

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Exercise 2 –  Protection CT1-2 for transformer incomer circuit:

Step 1 – Select ratings common to both the metering and protection CTs

  • Primary/secondary rated current: Use 300/1 A
  • Short-time withstand rating [Ith]: Use 10 kA rating
  • Primary circuit voltage [Up]: Use 12 kV rating

Step 2 – Select real output power

  • Real output power: typically > 1VA for digital type protection relay
  • Use 2.5 VA (this allows 1.5 VA for cable burden, etc.)

Step 3 – Calculate protection class 5PX

  • The instantaneous trip current level of protection relay OC1 is set to 15 × In.
  • ITRIP = 15 × 262 = 3930 A (primary current)

Note: In most digital protection relays, the trip current levels are set with respect to the secondary current. In this case

  • ISEC = 3900/300 × 1 = 13.1 A
  • The instantaneous trip current level for the CT secondary is 13.1 A

The trip current level should fall between 100 to 50% of the accuracy limit factor (ALF). Using an ALF of 10 (5P10), the trip current level of 3930 A falls outside the range 100% to 50% ALF, so a 5P10 protection class CT is not suitable.

  • 100%(ALF) = 1.0 × 10 × 300 = 3000 A
  • 50%(ALF) = 0.5 × 10 × 300 = 1500 A

We may notice that 1500 ≤ 3930 ≥ 3000 A. Using an ALF of 15 (5P15), the trip current level of 3930 A falls within the range 100% to 50% ALF so a 5P15 protection class CT is suitable.

  • 100%(ALF) = 1.0 × 15 × 300 = 4500 A
  • 50%(ALF) = 0.5 × 15 × 300 = 2250 A

We may notice that 2250 ≤ 3930 ≤ 4500 A. Use protection class 5P15

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Exercise 3 –  Protection CT2 for transformer feeder circuit:

Step 1 – Calculate transformer TXR2 nominal primary current: In (A)

  • In = S/(√3 × U) = 2000/(√3 × 11) = 105 A
  • The primary current for TXR2 is 105 A

Step 2 – Calculated maximum expected short circuit current at CT2 installation: Isc (A)

  • Ignoring any power cable or busbar impedances
  • Isc = In × 100/Z = 105 × 100/5 = 2100 A
  • The maximum expected short circuit current at CT2 is 2100 A

Step 3 – Select protection CT2 ratings

  • Primary rated current Ipr = (1.0 – 1.25) × In = (1.0 – 1.25) × 105
    Use a rating of 150 A
  • Secondary rated current Isr
    Use a rating of 1 A
  • Short-time withstand rating, Ith ≥ Isc
    Use a rating of 10 kA
  • Primary circuit voltage Up ≥ U
    Use a ratings of 12 kV
  • Real output power: Typically > 1 VA for digital type protection relay.
    Use 2.5 VA (this allows 1.5 VA for cable burden, etc.)

Step 4 – Calculate protection class 5PX

  • The instantaneous trip current level of protection relay OC2 is set to 10 × In
  • ITRIP = 10 × 105 = 1050 A (primary current)

Note: In most digital protection relays, the trip current levels are set with respect to the secondary current. In this case

  • ISEC = 3900/300 × 1 = 13.1 A
  • The instantaneous trip current level for the CT secondary is 7 A

The trip current level should fall between 100 to 50% of the accuracy limit factor (ALF). Using an ALF of 10 (5P10), the trip current level of 1050 A falls within the range of 100% to 50% ALF so a 5P10 protection class CT is suitable.

  • 100%(ALF) = 1.0 × 10 × 150 = 1500 A
  • 50%(ALF) = 0.5 × 10 × 150 = 750 A
  • We may notice that 750 ≤ 1050 ≤ 1500 A
  • Use protection class 5P10

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2. NEMA/IEEE Ratings

These ratings are typically used for current transformers manufactured or used in North American installations. As well as a stated primary to secondary nominal current ratio, the device also carries an overall accuracy rating in the format.

AC-CR-BU

Where:

  • AC = accuracy class
  • CR = class rating
  • BU = maximum burden (ohms)

2.1 Accuracy class

Designates the accuracy of the secondary current with respect to the primary rated current. This accuracy is only guaranteed provided the maximum burden is not exceeded.

Accuracy class Tolerance at 100% primary current
1.2 ±1.2 %
0.6 ±0.6 %
0.5 ±0.5 %
0.3 ±0.3 %

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2.2 Class rating

Designates the intended application of the device.

  • B = for metering applications
  • H = for protection applications. The CT secondary accuracy is guaranteed at 5 to 20 times the nominal primary rated current

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2.3 Burden

The maximum load allowed to be connected to the current transformer secondary, to guarantee the accuracy class. The maximum burden includes secondary cable/wire, connectors and the load.

The following table converts burden in ohms to VA, for a 5 A secondary.

Ω 0.04 0.06 0.08 0.12 0.16 0.20 0.24 0.28 0.32 0.36 0.40 0.48 0.56 0.64 0.72 0.80
VA 1 1.5 2 3 4 5 6 7 8 9 10 12 14 16 18 20

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tabela

2.4 Examples

0.5-B-0.1

This example indicates a current transformer with an accuracy of ±0.5%, and a maximum allowable secondary burden of 0.1 Ω (or 2.5 VA on a 5 A secondary CT). This is a metering class rated current transformer.

1.2-H-0.2

This example indicates a current transformer with an accuracy of ±1.2%, and a maximum allowable secondary burden of 0.2 Ω (or 5 VA on a 5 A secondary CT). This is a protection class rated current transformer.

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Sources:

  1. Medium Voltage Application Guide by Aucom
  2. Electric Power Substations Engineering By James C. Burke
  3. Selection of current transformers and wire sizing in substations – Sethuraman Ganesan; ABB Inc.



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Backup fault protection for generators in


The purpose of generator backup protection

It is a common practice to use the differential relay as primary fault protection for the generator. Backup fault protection is also highly recommended to protect the generator from the effects of faults that are not cleared because of failures within the normal protection scheme. The backup relaying is automatically applied to provide protection in the event of a failure at the generation station, on the transmission system, or both.

Backup fault protection for generators in case of a failure at the generation station
Backup fault protection for generators in case of a failure at the generation station

Specific generating station failures would include the failure of the generator or Generator Step Up (GSU) transformer differential scheme. On the transmission system, failures would include the line protection relay scheme or the failure of a line breaker to interrupt.

Table of contents:

  1. Implementation of backup fault protection
  2. Standard overcurrent relays
  3. Voltage-dependent relays
  4. Voltage supervised overcurrent relays
    1. Voltage-controlled and voltage-restrained relays
    2. Application options and fault sensitivity
  5. Other distance relay applications

1. Implementation of backup fault protection

Figure 1 shows the sample system generator. Backup protection is provided by distance relays (Device 21) or voltage supervised overcurrent relays (Device 51V). These relays can be connected to CTs at the neutral end of the generator or they can be connected to CTs at the generator terminals.

The neutral end configuration is preferred because this connection will allow the relaying to provide protection when the unit is off line. Terminal connected relays will not see internal generator faults for this condition, because there is no relay current.

If the scheme is intended to provide backup protection for both generating station and system faults, the backup relays should initiate a unit shutdown. This entails tripping the breaker on the high-voltage side of the GSU, the generator field breaker, the auxiliary transformer breakers and initiating a prime mover shutdown.

If the station configuration included a generator breaker it would be tripped instead of the high-voltage breaker.

When relays are applied solely to backup transmission line relaying, only the GSU transformer or generator breaker need be tripped. This would allow a faster resynchronizing after the failure has been isolated. This assumes the unit can withstand the effects of the full load rejection that will occur when the outlet breaker opens.

If the unit cannot withstand this transient, a unit shutdown must be initiated.

Generator online protection scheme
Figure 1 – Generator online protection scheme

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2. Standard Overcurrent Relays

Standard overcurrent relays are not recommended for backup protection of a generator. The backup relay must be capable of detecting the minimum generator fault current. This minimum current is the sustained current following a three-phase fault assuming no initial load on the generator and assuming the manual voltage regulator in service.

If the automatic voltage regulator where service, it would respond to the fault-induced low terminal voltage and boost the field current, thus increasing the fault current. The assumption of no initial load on the generator defines the minimum field current to drive the fault.

Typically, a generator’s synchronous reactance, which controls the value of the sustained fault current, is greater than unity. If the generator is unloaded and at rated terminal voltage (Et = 1.0) prior to the fault, the sustained short-circuit current will be 1/Xd which will be less than full load current. In the case of the sample system generator Xd = 1.48 and the resulting sustained three-phase fault current would be 0.67 pu or 67% of full load current.

A standard overcurrent relay must be set above load and could not detect the minimum sustained fault current. Tripping would be dependent on rapid relay operation before the fault current decays below the relay’s pickup setting.

Figure 2 plots the decaying current for the minimum fault condition on the sample system generator vs. an overcurrent relay set to carry full load. The figure shows that the relay must be set with a very short time delay (Time Dial = 1/4) to intersect the current plot to assure tripping.

This fast tripping is undesirable, because it would preclude coordination with system relays and could cause misoperation during system disturbances that do not require protective action.

Fault clearing with overcurrent relay
Figure 2 – Fault clearing with overcurrent relay

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3. Voltage-Dependent relays

The problems associated with standard overcurrent protection can be overcome if fault detection is based on current and voltage. At full load, the generator terminal voltage will be near rated voltage. Under sustained three-phase fault conditions, the internal generator impedance will increase to the synchronous value and the terminal voltage will decrease sharply.

Both distance relays and voltage supervised overcurrent relays use the voltage degradation to differentiate between load current and a sustained fault current condition. Because of this design, these backup relays are supervised by a potential failure detection element, device 60. This element blocks tripping in the event of an open phase or blown fuse in the potential circuit.

Without this blocking feature, these instrument circuit malfunctions would trip the fully loaded unit.

The decision to use a 21 or a 51 V function as backup protection is normally dependent on the type of phase protection applied on the transmission or distribution system to which the generator is connected.

Distance backup protection is chosen if phase distance relaying is applied on the transmission system. A 51 V function is chosen if overcurrent relays are used for phase protection on the connected system. These choices are made to facilitate relay coordination.

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4. Voltage Supervised Overcurrent Relays

4.1 Voltage-controlled And Voltage-restrained Relays

There are two kinds of voltage-supervised overcurrent relays used in generator backup applications. The voltage-restrained overcurrent relay is normally set 125–175% of full load current. The relay uses voltage input from the generator terminals to bias the overcurrent setpoint.

At rated voltage, a current equal to the setpoint is required to actuate the relay. As input voltage decreases, presumably
due to a short circuit, the overcurrent setpoint also decreases. Typically a current equal to 25% of the setpoint is require to operate the relay at zero volts input.

Figure 3 is a typical pickup characteristic for a voltage-restrained relay.

The voltage-controlled relay is set below full load with sufficient margin to detect the minimum fault current. The relay includes an undervoltage element that senses generator terminal voltage. If the voltage is above the undervoltage element setting, the overcurrent unit is not functional.

When voltage is depressed by a fault, the undervoltage element drops out, allowing the relay to operate as a standard overcurrent relay in accordance with its pickup and time delay settings.

Voltage-restrained overcurrent relay characteristic
Figure 3 – Voltage-restrained overcurrent relay characteristic

The voltage-restrained relay is more difficult to apply because operating time is a function of both current and voltage.

The voltage-restrained relay has two adjustable setpoints, a voltage-dependent minimum pickup current, and a time delay setting. The voltage-controlled relay has a voltage-independent current pickup setting, a time delay setting, and an undervoltage drop out setting.

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4.2 Application Options and Fault Sensitivity

Voltage-supervised overcurrent relays allow many input options. The 51 V function comprises three single-phase units. The current and voltage connections are not standardized. Phase-to-neutral or phase-to-phase voltages can be applied in conjunction with line or delta currents.

There is also the option of voltage-controlled or voltage-restrained relays.

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5. Distance Relays

The term distance relays refers to a general class of relays that measure circuit impedance. The relay distinguishes between fault current and load current in a manner similar to the 51 V functions. The  voltage applied to the distance relay tends to restrain operation, while current promotes operation.

Both phase and ground distance relays are applied on the transmission system. Unique relay designs are required for phase and ground fault protection.

There are many different algorithms  used in these relays, but in all cases the common goal is to measure the positive sequence impedance from the relay to the fault. When full fault protection is provided by distance relaying, six elements are required, phase elements A–B, B–C, C–A and ground elements A–G, B–G, and C–G.

Phase distance relays are applied at generators for system backup protection. Ground distance relays are not applied. Most generators are grounded through impedance to limit the ground fault current. Specialized ground fault protection schemes are required.

When a generator is solidly grounded and connected to a distribution system directly or through a wye-wye transformer, overcurrent ground relays provide superior fault sensitivity and economy when compared to ground distance relays. Overcurrent ground relaying is applicable because generator ground faults do not decay to values less than full load current and ground overcurrent relays are not subject to setting limitations due to load current.

Likewise, when a generator is connected to a system through a delta-wye grounded transformer, backup ground protection is usually provided by a time overcurrent ground relay connected in the transformer neutral.

https://www.youtube.com/watch?v=8E6yQZ5WMnc

For example, SEL-700G protection relay offers three choices for system backup protection. You can select one or more of the available elements:

  • Distance (DC),
  • Voltage Restraint (V), or
  • Voltage Controlled (C) Overcurrent elements.

Modern protective relays provide four zones of phase step distance protection. Functions are positive sequence voltage polarized mho characteristics. The reach of the three forward looking zones can be compensated for a delta-wye transformer.

Zone 4 is reversed and disregards any transformer between the relay and the fault in the forward direction. Zones 1, 2, 3, and 4 each include independent timers for phase step distance protection.

Out-of-step blocking monitors swing condition and blocks tripping. Out-of-step tripping logic is provided with a choice of two or three mho type characteristics with adjustable shapes.

Forward and reverse share a common maximum reach angle. Loss of synchronism or a power swing between two areas of the power system is detected by measuring the positive sequence impedance seen by the relay over a period of time as the power swing develops.

Generator protection relay SEL-700 functionalscheme
Figure 4 – Generator protection relay SEL-700 functionalscheme

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5.1 Other Distance Relay Applications

Other applications of the 21 function are also possible. Phase distance relaying can be connected to CTs at the generator terminals with the 21 function connected to look into the generator instead of the system. This relay can be applied without a time delay to provide fast backup clearing for generator faults when connected to the system.

Many generator protection microprocessor packages include two phase distance relay functions. One zone can be implemented with a short reach and a short time delay sufficient to coordinate with high-speed bus and line relaying plus breaker failure time if applicable. The second zone is then set to see into the transmission system with a delay sufficient to coordinate with zone 2 line relaying and applicable breaker failure time.

This scheme can provides 0.3 sec clearing for high current faults in the vicinity of the generator as opposed to the single zone scheme that would require a delay of about a second to coordinate with zone 2 and breaker failure relaying.

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Sources:

  1. Protective relaying for power generation systems by Donald Reimert
  2. SEL-700G Generator Protection Relay by SEL
  3. LPS-O System backup for generators and transmission lines by GE



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Four special connections of current


Metering and protection CTs

As you should already know, current transformers are used for metering and relay protection purposes. When we are talking about current transformers used for metering, their performance is of interest during normal loading conditions. Metering transformers may have very significant errors during fault conditions, when the currents may be several times their normal value for a very short time.

Four special connections of current transformers in relay protection applications
Four special connections of current transformers in relay protection applications (photo credit: merko.ee)

Since metering functions are not required during faults, this is not significant.

Current transformers used for relaying are designed to have small errors during faulted conditions, while their performance during normal steady-state operation, when the relay is not required to operate, may not be as accurate. In spite of this difference, all (measuring or relaying) CT performance may be calculated with the same equivalent circuit.

The different values of equivalent circuit parameters are responsible for the difference in performance between the various types of CTs. Note that the performance of CTs when they are carrying the load current is not of concern as far as relaying needs are concerned.

It’s important to underline that protective-relay performance depends on the accuracy of the CTs not only at load currents, but also at all fault current levels.

Accuracy can be visualized as how closely the secondary wave shape resembles the primary wave shape. Wave shape and phase difference are both components of the accuracy classification.

The CT accuracy at high overcurrents depends on the cross section of the iron core and the number of turns in the secondary winding. The greater the cross section of the iron core, the more flux can be developed before saturation. Saturation results in a rapid decrease in transformation accuracy.

The greater the number of secondary turns, the less flux that is required to force the secondary current through the relay. This factor influences the burden the CT can carry without loss of accuracy.

Let’s see four non-standard connections of CTs used in protection applications:

  1. Auxiliary current transformers
  2. Wye and delta connections
  3. Zero-sequence current shunts
  4. Flux-summing CT

1. Auxiliary current transformers

Auxiliary current transformers are used in many relaying applications for providing galvanic separation between the main CT secondary and some other circuit. They are also used to provide an adjustment to the overall current transformation ratio.

CT ratios have been standardized, and when other than a standard ratio is required an auxiliary CT provides a convenient method of achieving the desired ratio. The auxiliary CT, however, makes its own contributions to the overall errors of transformation.

In particular, the possibility that the auxiliary CT itself may saturate should be taken into consideration. Auxiliary CTs with multiple taps, providing a variable turns ratio, are also available. The burden connected into the secondary winding of the auxiliary CT is reflected in the secondary of the main CT, according to the normal rules of transformation:

If the auxiliary CT ratio is l : n, and its burden is Zl, it is reflected in the main CT secondary as Z1/n2.

Auxiliary CT connections
Figure 1 – Auxiliary CT connections

Example

Consider the CT connection shown in Figure 1. CT1 has a turns ratio of 1200 : 5, while CT2 has a turns ratio of 1000 : 5. It is desired that when the primary current flows through the two lines as shown, the current in the burden be zero. Assume the primary current to be 600 A.

The current in the secondary winding of CT1 is 2.5 A and that in the secondary winding of CT2 is 3 A. By inserting an auxiliary CT with a turns ratio of 3 : 2.5 or 1.2:1 in the secondary circuit of CT1, the current in the auxiliary CT secondary becomes 3 A.

With the polarity markings as shown, the burden current is zero.

The burden on CT2 is Zb, while that on CT1 is Zb × (1.2)2 = 1.44 Zb. The burden on the auxiliary CT is of course Zb.

CT connections such as these are used in various protection schemes, and utilize the fact that, assuming no auxiliary CT saturation, when the primary current flows uninterrupted through the two primary windings the burden current remains zero, while if some of the primary current is diverted into a fault between the two CTs the burden current is proportional to the fault current.

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2. Wye and delta connections

In three-phase circuits, it is often necessary to connect the CT secondaries in wye or delta connections to obtain certain phase shifts and magnitude changes between the CT secondary currents and those required by the relays connected to the CTs.

Wye- and delta-connected CTs
Figure 2 – Wye- and delta-connected CTs

Consider the CT connections shown in Figure 2. The wye connection shown in Figure 2(a) produces currents proportional to phase currents in the phase burdens Zf and a current proportional to 3I0 in the neutral burden Zn. No phase shifts are introduced by this connection.

The delta connection shown in Figure 2(b) produces currents proportional to (I’a − I’b), (I’b − I’c) and (I’c − I’a) in the three burdens Zf.

If the primary currents are balanced, (I’a − I’b) = √3|I’a| exp(jπ/6), and a phase shift of 30° is introduced between the primary currents and the currents supplied to the burdens Zf.

By reversing the direction of the delta windings, a phase shift of −30° can be obtained. The factor √3 also introduces a magnitude change which must be taken into consideration. We will discuss the uses of these connections as we study various relaying applications.

Delta connected CTs (VIDEO #1)

Delta connected CTs (VIDEO #2)

Wye connected CTs (VIDEO)

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3. Zero-sequence current shunts

Recall the wye connection of CT secondaries shown in Figure 2(a). Each of the phase burdens Zf carries phase currents, which include the positive, negative and zero-sequence components.

Sometimes it is desired that the zero-sequence current be bypassed from these burdens. This is achieved by connecting auxiliary CTs which provide an alternative path for the zero-sequence current. This is illustrated in Figure 3.

Zero-sequence current shunt
Figure 3 – Zero-sequence current shunt

The neutral of the main CT secondaries is not connected to the burden neutral. Instead, a set of auxiliary CTs have their primaries connected in wye and their secondaries in delta.

The neutral of the auxiliary CTs is connected to the neutral of the main secondaries through the neutral burden Zn. The secondary windings of the auxiliary CTs provide a circulating path for the zero-sequence current, and it no longer flows in the phase impedance burdens Zf.

Zero-sequence current transformer
Zero-sequence current transformer (photo credit: voltage-disturbance.com)

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4. Flux-summing CT

It is possible to obtain the zero-sequence current by using a single CT, rather than by connecting the secondaries of three CTs as in Figure 2(a). If three phase conductors are passed through the window of a toroidal CT, as shown in Figure 4(a), the secondary current is proportional to (Ia + Ib + Ic) = 3I0.

Since this arrangement effectively sums the flux produced by the three phase currents, the CT secondary contains the true zero-sequence current.

In a connection of three CTs as in Figure 2(a), any mismatches between the three CTs will introduce an error in zero-sequence current measurement.

This is entirely avoided in the present application.

Flux-summing CT: (a) without and (b) with current in the cable sheath
Figure 4 – Flux-summing CT: (a) without and (b) with current in the cable sheath

However, it must be recognized that such a CT application is possible only in low-voltage circuits, where the three phase conductors may be passed through the CT core in close proximity to each other.

If the three phase conductors are enclosed in a metallic sheath, and the sheath may carry some (or all) of the zero-sequence current, it must be compensated for by threading the sheath grounding lead through the CT core, as shown in Figure 4(b).

The ampere-turns produced by the sheath current are now cancelled by the ampere-turns produced by the return conductor, and the net flux linking the core is produced by the sum of the three phase currents. This sum being 3I0, the burden is once again supplied by the zero-sequence current.

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Sources:

  1. Power System Relaying by Stanley H. Horowitz and Arun G. Phadke 



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Reactive power compensation in electrical


Compensation of reactive power

Compensation of reactive power applied in buildings or small facilities operates in the first and second quadrants of the coordinate system. Increasingly, complex industrial plants, for example plants burning wood dust, are using generators driven by steam engines running parallel to the main supply.

Reactive power compensation in electrical plants with generators
Reactive power compensation in electrical plants with generators (photo credit: ingelmec.com.pe)

This technical article explains the technical and economic aspects regarding the desired power factor or reactive energy to be charged. If generators are feeding back active energy to the distribution company, one speaks of four-quadrant operation.

The tariff situation then has new aspects with regard to the reactive energy consumption to be charged. The tariff requiring an average power factor of cos φ = 0.9 lagging becomes invalid as explained in the following paragraphs.

Furthermore, it renders prominent the meanings of power factor cos φ and reactive power Q as totally different electro-physical quantities. One could describe them in an inequality like:

cos φ ≠ Q ≠ cos φ

Thus power factor is not identical to reactive power and vice versa.

Table of contents:

  1. The complexity of putting generator(s) into action
  2. Automatic control of reactive power within four quadrants
    1. Technical considerations
    2. Bargaining considerations
    3. Example
  3. Conclusions

1. The complexity of putting generator(s) into action

Any plan for putting generator(s) into action must be declared to the electricity supplier and registered in a specially negotiated contract. It determines to which incoming supply (if more than one) the generator should be connected. Specifications issued by national or international institutions should be strictly followed.

First of all, power generator units running steadily in parallel to the main supply must be distinguished from emergency power generator units at hospitals that are activated in case of any fault or collapse in the main supply. Emergency power generator units are in use for a short time, mainly until the grid is active again. This situation may be excluded by referring to four-quadrant operation.

Power generator units may be driven by primary energy sources like water or wind power, solar cell plants, cogeneration district heating plants or fuel cells. The electrical energy may be generated by synchronous or asynchronous generators as well as by DC generators with DC/AC converters.

The following criteria on driving generators in parallel to the grid are to be noted: voltage stability, quality of the voltage and synchronized frequency. It must further be taken into consideration whether an autarchic operation will be intended.

However, this is possible mainly with synchronous generators.

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2. Automatic Control of Reactive Power within Four Quadrants

2.1 Technical Considerations

Figure 1 illustrates the four quadrants of a coordinate system. If generators are in operation four different load situations may occur:

  • Quadrant I: Consumers import (+) active and reactive energy.
  • Quadrant II: Consumers import (+) active energy and export (−) reactive energy.
  • Quadrant III: Consumers export (−) active and reactive energy.
  • Quadrant IV: Consumers export (−) active energy but import (+) reactive energy.
Reactive power control within all four quadrants
Figure 1 – Reactive power control within all four quadrants

In quadrants III and IV the generators are feeding back active energy to the electricity supplier to be measured by a separate kWh-meter.

Most attention is paid to the situation within quadrant IV! Asynchronous generators especially are able to feed back active energy to the grid, but they import reactive energy for magnetizing!

The situation in quadrants I and II is well known and can be referred as a standard. There the control of reactive power is explained by means of an automatic controller. One can recognize the insensitive bandwidth limited by the so-called C/k threshold lines and the turning around of the zero point of the coordinate system depending on the selected power factor target.

Figure 1 indicates two selected power factor targets: 0.85 lagging and preset to unity.

Regarding load vector 3, one capacitor step is sufficient to achieve the power factor of approximately 0.85 lagging and the controller ‘stands by’. In order to achieve the desired power factor of cos φ = 1, the reactive power controller switches in three further capacitors.

‘Confusing power factors’ in four-quadrant operation (current transformer fitted at incoming supply point)
Figure 2 – ‘Confusing power factors’ in four-quadrant operation (current transformer fitted at incoming supply point)

Even though a generator is running in parallel just to reduce the consumption of the active energy from the main supply, the vectors are still moving within the first or second quadrant only (see Figure 2b).

However, if the generator takes over the complete active power consumption and even feeds back active energy into the electricity supplier’s grid, then the vectors change into the third or fourth quadrant (see Figure 2c).

Most electronic reactive power controllers have a digital display indicating the actual power factor. For control of reactive power operating within all four quadrants, confusing power factors may be indicated, as shown in Figure 2c, if the generator is feeding back. Controlling within all four quadrants, any value of the power factor may be indicated from 0 to 1 in either the first or third quadrant and from 1 to 0 in the second and fourth quadrants.

Thus the controller indicates any possible value within 360° of the coordinate system, provided that it is suitable for four-quadrant operation. This is the pre-supposition that the reactive power controller is applicable for operation within all four quadrants.

It must be underlined again that the actual power factor cos φa does not say anything about the actual amount of reactive power Q.

Vector 4 in quadrant IV in Figure 1 symbolizes the load situation where the generator is covering the consumption of active power totally and is feeding back an identical amount to the grid in addition. If the target power factor had been preset to 0.85 lagging, the controller would suddenly intend to compensate to the 0.85 leading side!

The C/k bandwidth is extended from the first quadrant via zero into the third quadrant. This is called the mirror-imaging behaviour of the controller.

It does not ensure that the compensation bank will be sufficient to compensate according to the 0.85 leading side (see vector 6). Seven capacitor steps would become necessary in order to achieve this power factor target.

As is well known, there is the disadvantage of a voltage increase when compensating into the capacitive area. If the compensation bank was not able to achieve this high power factor due to insufficient steps, many modern reactive power controllers would trigger an alarm.

To get proper control of reactive power does not mean presetting the power factor target into the second quadrant, for example the 0.9 leading side in order to achieve the 0.9 lagging side when controlling in the fourth quadrant (see Figure 1).

The simplest way to solve this problem is to preset the power factor target to unity, cos φd = 1. With this power factor target, symmetrical control of reactive power is ensured within all four quadrants (see vectors 5 and 2). Thus if the reactive power compensation is working within all four quadrants the capacitors’ capacitance is determined sufficiently in order to achieve an average power factor of unity, cos φ = 1.

Remember that the total compensation of reactive power saves active energy (kWh) due to power losses along the leads. This solution is indispensible not only from a technical viewpoint, but also from the economical side as well, as described in the next section.

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2.2 Bargaining Considerations

As mentioned above, customers with their own generator(s) are obliged to compensate reactive power to a desired power factor much closer to unity, cos φd = 1.

Any standard tariff agreement on achieving an average power factor of 0.9 for instance becomes invalid. This standardized contract agrees that 48.5% of the consumption of active energy is free of charge with respect to the amount of reactive energy. In simple terms, if the consumption of active energy amounts to, for example, 1000 kWh per billing period, then 485 kvarh of reactive energy is free of charge.

The very human behaviour of customers with generators ensures that they will pay attention to bringing down the consumption of active energy to zero. Then, at the end of a billing period, the electricity invoice may indicate 0 kWh of active energy but, for example, 17 000 kvarh consumption of reactive energy!

As a matter of course the electricity company will not grant any kvarh without charging. Many electrical plants with generators are using asynchronous generators, that is asynchronous motors running with so-called negative ‘slip’. Independent of whether the engine is running in motor or generator mode, it consumes reactive energy for magnetizing the iron core steadily.

Thus each customer intending to reduce the consumption of active energy particularly or even totally by the generator(s) is obliged to compensate any reactive energy totally as well, except if the customer has negotiated a special contract with the electricity utility company.

The following example underlines the facts described above.

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2.3 Example

An asynchronous motor of 100 kVA rated power is to be driven in generator mode. Its nominal power factor is 0.82 inductive. Although it is feeding back active energy into the grid, the consumption of reactive power amounts to:

cos φ = 0.82φ = 34.9°sin φ = 0.572

The reactive power of the generator is to be calculated by:

Q = S × sin φ = 100 kVA × 0.572 = 57.2 kvar

Within one day, or 24 hours, the varmeter will count up to 1373 kvarh or 41 200 kvarh approximately per month if the generator is running steadily, for example at water power stations.

In operating with synchronous generators the consumption of reactive energy depends on the preset exciting rate. They are preset to a power factor referring regularly to the lagging side. Then the reactive power of the generator is calculated in the same way as for the asynchronous one.

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3. Conclusions

Compensating reactive power within all four quadrants of the coordinate system due to generators running in parallel requires consideration of technical and economic facts in totally another way to that known from classical two-quadrant operation.

In general the aim is to compensate in achieving unity, cos φ = 1, as close as possible. The compensation bank has to be determined accordingly and the reactive power controller must be suitable for control within all four quadrants.

It is a matter of course that the controller’s current transformer must ‘seize’ the reactive current of the generator(s) as well. Thus the feed-in point of the generator(s) always has to ‘look’ to the L side of the current transformer’s casing.

Individual, national or international instructions are to be followed.

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Source: Reavtive power compensation by Wolfgang Hofmann, Jurgen Schlabbach and Wolfgang Just (Purchase hardcover from Amazon)



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