Yes. In each contingency user defined no. of elements can be outaged.
Whether Transformer primary should always be H.V.?
Primary voltage can be either H.V. or L.V. depending on the taps provided.
Why Cost Coefficients are given in Generator data?
These are the cost coefficients used in real power optimization study.
Why breaker rating is given in all menus?
The breaker rating in all menus is just to verify whether the fault MVA is above or below the breaker rating.
Where participation factor field is used?
Participation factor is considered in Flat Frequency Control option to simulate the secondary control effect.
Difference between Schedule power and real power.
Schedule power is the power generated by the generator at that instance and it should be less than or equal to maximum real power generation.
What is the significance of Contingency Weightage?
Contingency Weightage is used to increase the severity of given outage for a particular bus or line. Normally the weightage value is unity. However, if a particular bus voltage deviations should not occur for any outage, and even for small deviations, that outage need to be given higher ranking, then the bus weightage no. is given greater than unity say, 5. Then the voltage deviation is multiplied by 5 times, and hence the contingency ranking will go high. For 400 kV buses and buses connected to neighbouring grid, the weightage can generally be increased, then line weightage is given more than unity. For tie lines and important lines in the grid, which should never be overloaded, line weightage can be increased.
Why primary grounding resistance or reactance is used?
Primary grounding resistance or reactance is used to add neutral ground resistance or reactance to reduce the fault current or to introduce any earthing transformer. It is in elements data of transformer
How to convert H value from machine base to system base?
What is the significance of Phase shifting transformer / Phase shift angle?
Phase shifting transformer is used in certain systems to push more power in a specific line by introducing angle difference . The phase shift angle in the element data corresponds to the shift given to boost the power flow. Phase angle in the library is the phase shift introduced due to vector connection i.e. 1'O clock position or 11' O clock position etc.
LOAD FLOW STUDY
Concepts of tie line with reference to MiPower
The Tie line refers to those lines connecting one utility to other or those lines, which island the system, when kept open. In inter connected operation of power system, it is the responsibility of individual utility to operate the system such that tie line exchange remains constant, Consider two systems A& B connected by a tie line as shown in figure.
Following an increase in load in area B, say by 25 Mw, after the primary control (governor action), a case may arise wherein A will be exporting 10MW extra to B. Hence the representation becomes.
If the flat tie line control were to be there, then A to B should be brought back to 50 MW I.e. the tie line scheduled power. In order to do that, rise signal should be given to generator in area B to increase the generation. The control is called secondary control or AGC (Automatic generation control). In MiPower, it is possible to schedule the tie line flow, by changing the generator set points of all generators trying to participate in the secondary control.
A simple system with two generators and 4 loads all connected at same voltage through bus couplers. The total load is 4x7.5MW. One generator is scheduled for 20 MW and other is slack with generation capacity of 10 MW, the program is not saying converged but it shows generation output of slack generator as 29.54 MW with 0 MVAR and other generator with 0 MW and 12 MVAR while MVAR load total is 13 MVAR. What is the reason ?
In Elements - Generator Data there is one Heading called as "Real power optimization Data under which Give Real Power Min = 0.0, And Real Power Maximum = ( your specified power or scheduled power )
If in the system, generation is more and load is less, slack bus takes / absorbs additional power
Observe the following in the LFA report
Total Real Power Generation
Total Reactive Power Generation
Total Real Power Load
Total Reactive power Load
The above values should almost match to get converged result
Which are the primary parameters considered in a load flow study?
P Active power into the network.
Q Reactive power into the network.
|V| Magnitude of bus voltage
& Angle of bus voltage referred to a common reference.
Short Circuit Study
Which are the parameters considered for short circuit study?
Generator
Transient(Xd') or sub-transient (Xd'') reactance is considered for +ve sequence.
-ve sequence reactance X2 approximately equal to Xd''
Zero sequence reactance is 0.1 to 0.7 times Xd''
Transmission Line
+ve seq impedance Z1 equal to -ve seq impedance Z2
Zero seq impedance Z0 depends upon return path, ground wires and earth resistivity.
X0 is 2 to 2.5 times +ve seq reactance X1
R0 is 5 to 10 times +ve seq reactance R1
B0 is 0.6 to 0.8 times +ve seq susceptance B1
Why Generator MVA rating, transformer MVA rating are not appear in short circuit report?
In the load flow study the transformer, Generator MVA rating are relevant as the loading on the equipment are compared with the rating.In short circuit study the fault level should be compared with breaker rating . Hence only breaker ratings are given in short circuit study.
In short circuit study R / X ratio of short circuit path is mentioned. What does it signify and how is it calculated?
R/X ratio of short circuit path is computed in case of 3 phase fault. The value is used in the selection of asymmetrical braking capacity from the symmetrical braking capacity. The asymmetrical braking capacity should be selected based on the R/X ratio ( i,e resistance to reactance ratio of driving point impedance and the breaker operating cycles. Please refer Chapter 10, Section 10.1 & 10.6 of "Elements of Power System Analysis", Fourth edition, McGraw Hill publication by W.D Stevenson, for further details.
Transient Stability Study
A 3phase to ground fault at a particular bus , then the program is giving "Divide by zero" Error.
Divide by zero error which encountered is due to fault impedance value which might be zero. If you want to neglect the resistance give fault impedance value as 0.000001.
When a frequency of bus is plotted where generator is removed, a steady frequency of 50 Hz is shown for total duration of study. Why is it so ?
Once the generator is removed from the system the program assume that the user is not interested in its bahaviour, rather he is interested in rest of the system. Hence generator machine equations are not solved.
For Transient Studies MiPower should be capable of simulating fault at any length of line.
Simulation of fault at any length of line in transient stability study is not possible with the POWERTRS. However, a dummy bus can be created at the required location and fault can be created at that bus.
Give frequency calculation procedure when different generators are swinging at different frequencies.
Frequency at any bus is computed by the expression
In transient stability we can not see the plots at the load buses. Only at generator buses plots can be seen.
To view load bus plots select those buses in VIZS buses. These plots are stored in the database area under TRS directory. In TRS directory bin files with M or L with .bin extension will be there . Open graph utility and press import button and browse the bin file 1AecoL.bin file in the database area under TRS directory . In this bin file you can see the line flows and r-x plots and load buses plots.
On clicking Graph button from Database Manager, program opens the machine plots(eg. 1Aeco0M.bin) bin file. So to view load buses plot click New button and press import button and browse the bin file 1Aeco0L.bin file in your database area under TRS directory. In this bin file you can see the line flows and r-x plots and load buses plots (if you open Graph through Database Manager).
Relay Co-Ordination
How to give instantaneous setting to overcurrent relays?
Phase instantaneous setting factor for R1 (in relay Database for Example 156 (CADG-51 (PI))
Min = 2.5, Max = 20
Phase instantaneous setting factor for R1 (In Element Relay) = 1.3
Let the fault current at Bus-2 if Fault occurs at vicinity of Relay R2 = 400 Amps
Then Relay setting of R1 = 1.3 * 400 = 520 Amps
Then, Setting calculated by the relay starts from minimum setting
I.e., 2.5 * 800 = 2000 > 520 Amps
Therefore Setting of the Relay = 2.5
If any relay in the library is selected, it should have instantaneous element and its setting should have been entered in Relay Database
Under setting select Instantaneous Phase
For example Refer Relay 136CDAG-51P1 stands for Phase Instantaneous)
Click on Setting Instantaneous Phase .It has a minimum setting of 2.5.and maximum setting of 20
With respect to the rated current of
1 Amp meaning that Minimum Setting = 2.5 times rated current.
Maximum setting = 20 times rated current
(Typical values are Min = 2.5 Max = 20)
Then in element typical value of Instantaneous factor will be 1.3 meaning that it has been set to 130% of remote bus fault current i.e. for this, relay should not operate instantaneously for remote bus fault current.
What is the minimum requirement of data for different power system elements like Motor, Transformer, Load, Line for carrying out relay co-ordination studies.
Minimum data required for relay co-ordination :
For all the elements, the short circuit data is a must i.e.
a) for generators, ra,X'd , X''d, X2 and X0 are required along with its MVA rating.
b) for line, positive and zero sequence parameters are required.
c) for transformer, MVA rating, impedance value, vector group, neutral grounding impedance if any are required .
d) for Induction motor, it is difficult to get the various parameters. However, we can make the approximation as r1 is negligible. X1 is negligible. Xm is very high. Z = sqrt(r2 x r2 + X2 x X2) corresponds to starting impedance taking 5 to 6 times as starting current. r2 and X2 are separated knowing the starting power factor which is in the
range 0.17 to 0.2. Motor thermal characteristics (hot and cold ) is required to select the motor relay.
Other data required for the relay co-ordination is CT details, relay location, type of relay and individual relay characteristics as per relay manufacturer catalogue.
How to set Power Swing blocking relay ?
Power swing blocking : From power system operation point of view it is not desirable to obtain tripping from a distance relay during a power swing. The fluctuations of voltage and current occuring in such a case can make it impossible for the relay to discriminate between a 3 phase fault and a heavy power swing. Detection of power swing is made by measuring the time that elapses between the operation of the two concentric impedance elements. The output from the impedance elements is fed to a logic circuit where it is determined whether it is a power swing or a fault that has occured on the network. This is done by considering the fact that the change in apparent impedance during power swing is very slow compared to the sudden change when a fault occurs. The time interval used in the power swing blocking element is 35-40 ms which means that if a change in apparent impedance is larger than this fixed time the power swing blocking element will block the operation of the distance relay for approximate 2 seconds. On the other hand if the change is faster than 35-40 ms then distance relay is permitted to operate in the normal way.The power swing blocking setting can be set if the distance relay is provided with power swing blocking element. For ex.for the RAZFE relay panel constant k4 gives the setting for power swing blocking element.
How to select Earth fault relay plug setting ?
The zero sequence fault current through the protective devices is determined by the fault study. 10% unbalance is assumed ( it can be user defined also) i.e. the relay should not operate for a fault current ( 0.1 x ilmax ) flowing through it.
For a given secondary rating different pickup currents are available for earth fault setting.
Following conditions are checked :
Percentage setting x CT primary rating > Unbalance factor x ilmax.
If this condition is satisfied,
The ratio of primary zero sequence maximum fault current is checked. This should be less than the percentage setting x CT primary rating and Maximum overload capacity.
