Relationship Between MVAR and MW

To my estimate you have not picked up the theme correctly and I am doubtful that the matter relates to gas turbine or a single unit.

Normally from the stand point of System Stability the angle between active and reactive power is carefully studied and adjustments in VAR is done accordingly in order to prevent system from collapsing in the event say a large portion of system load is abruptly cut off.

Systems widely differ, Operators in your case are complying with the instrutions given to them by someone like Load Dispatch Centre and for you to get a clear concept please refer your query to that governing body

Hi Mountk2, Thanks for your post. I spoke to the operator after you post and he gave me an instance of when one of the gas turbine units tripped because it was delivering 7mw but an operator forgot to adjust the mvar and it rose to nearly 6.5. This is where my problem lies. I would like to know whether there is a standard rule governing the ratio between mw and mvar on a gas turbine unit, beyond which the unit trips on self protection.

Do some experimentation yourself, while load on generator is about 7 MW start from lowest permissible MWAR and raise it as far as possible towards 6.5 limit given by the Operator. Check current of the exciter and asses the possibility that the current exceeds the maximum exciter current delivering capability at around 6.5 MWAR to have actuated over current protection causing the unit to trip.

With further information provided by you I have done some research accordingly:

A unit trips (gas turbine generator in your case) with sudden increase in load (MW) due to failure of any other unit, determination of the safe quantity of that extra abrupt load depends on the load angle and is generally assed by drawing power angle curve, similar is the case when prime mover input is suddenly increased.

While some of the respondents to your post have pointed out a possibility of reverse power but I do not agree to that.

hi, i think mountk2 has given u exactly want u want to understand. and that is the only reason for the Northeast Blackout happened in 2003 in us.. u can refer detailed report for the same.....

mvar is the Reactive Power which has leading PF & mw is Active Power which has lagging PF. So, by doing this he is adjusting positive PF adding it to negative to bring it to Unity or else winding will have more Load & it will affect for Losses in Windings.

This may be one reason to my knowledge.

I don't think this subject is within your domain. Leading and lagging PF have nothing directly to do with MW but both are to do with MVAR. Also the adjustment in question is not to reach any UNITY anywhere here!

Please check your knowledge on the subject and Thanks

dear,

Gas turbine is of 2 parts - Turbine - Mechanical unit ( Active power producer - MW)

Alternator - Electrical unit (Voltage out put - rating in MVA - current limit )

Fuel Gas input controls the active power out put.

But,, due to inductive loads, there is a reactive power also, in MVAR, which is not useful power , but can be leading or lagging. depend upon the power factor at bus.

Controlling MVAR means controlling power factor , which should always be in a lagging mode, other wise, there will be reverse power faults, burning alternators.

So, normally both the above actions are being taken by the operator, not only to control the MW by fuel regulation, but also the MVAR control, by regulating the voltage & Power factor. then you shall achieve the stability in operations in power plants. other wise, there will be cascading trippings / power shut downs etc...

Leading Power factor operation will not result in tripping of the set due to reverse power. Leading power factor has nothing to do with reverse power tripping. Load at leading power factor is a positive load and therefore no reverse power tripping will take place.

Since you are an intern in this power plant, Are you studying electrical engineering? What is your field and what is your subject of internship?

If your field is not electrical and want some insight:

Electrical Power generated using gas or steam or any other type of Prime mover has the same properties

Total power output is referred to as Apparent Power (symbole S)

S is in VA for Volt Ampere (MVA is Mega or million Volt Ampere)

S = P for Active power (W for watt and MW = mega Watt) + Q for Reactive Power (VAR Volt Ampere Reactive or Mega...) BUT the addition is Vectorial, i.e. you draw a rectangle triangle and place the MW value horizontally, then add the MVAR at the end but vertically then draw the hypothenuse which represents the MVA (S) therefore, in normal values S = Square root√ ( P² + Q²)

the Power Factor (PF) is the Cos of the angle made by S and P lines(φ).

You will notice that if you allow the MVAR to increase while the MW is the same, then your S will also increase: This is the total power produced by the Turbine (whether gas or else). You also notice that the MW did not increase since this represents the exixting ACTIVE load demanded by the grid.

the directive is not to overload the Turbine (Prime mover) and share the load with other primemovers (Generators) already in parallel on the grid. if the MVAR is too high, you deplete the reserve power available from the prime mover and this can trip the unit when ever there is a sudden demand of active power (or reactive) thus cascading other tripping possibly.

This MVAR adjustment is carefully monitored to keep generating power and maintaining the PF to near a fixed value usually 0.8 to 0.95 but never UNITY. The topic of power generation (Electrical) and the stability of the supply grid system is somewhat not so simple but can be understood simply.

* In a prior comment, a typical Generator Capability Curve was provided. This curve specifies the 100% rated steady-state capabilility that still has sufficient margin to survive standard transients and fault conditions. The steady-state capability is limited by the following:

- The stator currents. If the stator currents through the three phase stator are too high, the stator windings will overheat.

- The field current in the rotor winding. This is a DC current, and if it is too high the field windings will overheat. This current is supplied by the exciter, and it will also reach its limits.

- If the generator is operated at a leading power factor (PF), the excitation is low and the magnetic field strength is low. There is a risk of losing synchronization with the grid, which is not good.

* The three phase electrical power output to the grid is determined by the power supplied by the turbine. Increasing the power of the turbine directly increases the power output from the generator.

* Reactive power (which is not power at all, but rather energy oscillating around the system) generated is determined by the excitation, assuming that there are other generators on the grid. Changing the excitation of one generator will cause the distribution of reactive power to change among all generators on the grid. If there is only one generator on the grid, the reactive power is determined by the load, and there is nothing that can be done to change it assuming that the grid voltage and frequency are maintained.

* The best point to operate a generator is at a power factor (PF) of 1.0. A previous comment is incorrect in stating that this is not desirable. At a PF of 1.0, the maximum power output in watts from a generator is achieved while still staying within its ratings. Because the grid has lagging loads (inductive loads), in order to operate a generator at PF = 1.0, either other generators have to supply the lagging reactive power, or leading PF loads have to be added to cancel out the lagging loads. Examples of leading PF loads are capacitors and overexcited synchronous motors.

* When multiple generators are supplying a grid, the real power load (watts) is divided between them by adjusting the power inputs from all of the turbines. If one turbine supplies less power then another turbine must increase its power output to compensate.

* When multiple generators are supplying a grid, the reactive power (volt-amperes) is divided between them by adjusting the excitation. The higher the excitation, the higher the voltage output and the more lagging load a generator will supply (lagging PF). When one generator assumes more lagging reactive load, the lagging reactive load on the other generators decreases. The total load on the generators is determined by the sum of all of the loads on the grid (motors, lights, heaters, capacitors, computers, etc.). From this, you can see that if some generators supply "too much" lagging reactive power then other generators will be operating at leading power factors. Everything has to balance.

thanks for the detailed simple explanation you have given. GA.

on the subject of the p.f being less than 1: I am the one that stated this. For the simple reasons you have stated above, it will be impossible for someone to adjust the excitation and power to achieve unity pf on all gensets in the grid. The reactive power is dictated, as you said from the load in question, therefore there will be some reactive power floating arround to be provided by one or some of the units, UNLESS power factor corrective measures, as stated by yourself, is taken.

For the sake of the OP question, simply, there is no need to excite him to try and compensate at one location but rather to follow what the dispatch centre dictates and we need to simply explain what all these items mean. That is all.

Thank you for explaining the details.

A transmission line that is open at the consumer end (No- load) is a source of capacitive (leading) reactive power, while the heavily loaded line is a source of inductive (lagging) reactive power.

By adjusting the reactive power flow (VAR) the power station operator is actually changing the voltage drop.

In peak hours not only the customer loads causes big voltage drops but also the inductive component of the lines adds to the power flow and causes further voltage drops.

The generators at power stations can smoothly deliver adjustable lagging and leading power (MVAR) however the reactive power occupies the generation capacity and reduces the total generation capacity, the angle between active and reactive components both being vector quantities is taken into account.

Let me also add some information for you regarding to reactive power importance .

There are three reasons why it is necessary to manage reactive power and control voltage in power system design and operation

1- both customer and power-system equipment are designed to operate within a range of voltages, usually within 5% of the nominal voltage. At low voltages, many types of equipment perform poorly, light bulbs provide less illumination, induction motors can overheat and be damaged, and some electronic equipment will not operate at all.

2- reactive power consumes transmission and generation resources. To maximize the amount of real power that can be transferred across a congested transmission interface, reactive power flows must be minimized. Similarly, reactive power production can limit a generator's real power capability.
Third, moving reactive power on the transmission system incurs real power losses. Both capacity and energy must be supplied to replace these losses. Voltage control is complicated by two additional factors. First, the transmission system itself is a non linear consumer of reactive power, depending on system loading. At very light loading the system generates reactive power that must be absorbed, while at heavy loading the system consumes a large amount of reactive power that must be replaced. The system's reactive power requirements also depend on the generation and transmission configuration.

Consequently, system reactive requirements vary in time as load levels and load and generation patterns change. The bulk power system is composed of many pieces of equipment, any one of which can fail at any time. Therefore, the system is designed to withstand the loss of any single piece of equipment and to continue operating without impacting any customers. That is the system designed to withstand a single contingency. Taken together, these two factors result in a dynamic reactive power requirement. The loss of a generator or a major transmission line can have the compound effect of reducing the reactive supply and at the same time, reconfiguring flows such that system is consuming additional reactive power. At least a portion of the reactive supply must be capable of responding quickly to changing reactive power demands and to maintain acceptable voltages throughout the system. Thus, just as an electrical system requirement real power reserves to respond to contingencies, so too must maintain reactive power reserves.

Load can also be both real and reactive. The reactive portion of the load could be served from the transmission system. Reactive loads incur more voltage drop and reactive losses in the transmission system than do similar size (MVA) real loads. Vertically integrated utilities often include charges for provision of reactive power to loads in their rates. With restructuring the trend is to restrict loads to operation at near zero reactive power demand (a 1.0 power factor)

Dear Mr. Ottiv,

You have referred, "the relationship between mw and mvar"

Dear Mr. Ottiv,

Relationship between MW and MVAR is simple. It is MW/MVAR = Power Factor.

For a given MW, if MVAR is more means, the Line Current will be more, and Power Factor will be less. Hence, tripping due to over load is possible.

DHAYANANDHAN.S