When power plant is on standby, the induction motors may not be working or if working, will be at low load.
Thus, the power factor of these motors will be low.
The transformers will all be ON but working at low load. Thus, the magnetising current is likely to form a substantial portion of the transformer input current and the power factor will be low.
The flux and magnetising current for transformers and motors can be lowered (and thus improve the overall power factor) if the voltage input to the transformers can be lowered to below the rated voltage as applicable to the tap selected.
This is one way to improve the overall power factor of the plant when it is on standby mode.

Quote:

At generator transformer oltc is provided at HV side so as per my understanding if tap position is lowered then VARs import will be reduced because by lowering tap position the number of turns at primary i.e HV side increases which decreases magnetization current. This will reduce secondary voltage but the auxiliary transformer (11/6.6 kv) will increase tap in order to maintain constant 6.6 kv.
I want to know that my thinking is true or not.

No offense, but to me your logic doesn't track . . .

Sure you can lower the tap on the system to site transformer, lowering the intermediate voltage to your site; whether this is doable or not will depend on whether by doing this you will subject any equipment connected at that voltage level to below rated potential, which may cause problems, especially if that equipment has no facility to correct for lowered voltage supply.

Not only that, but when the intermediate to utilization tapchangers operate to compensate for their reduced supply voltage they will draw more inductive power from the transformer above them, negating the desired result.

If it is known that there will be seasonal variations in plant load of known duration, it may be advantageous to supply mechanical power to one of the major loads within the site using a grossly oversized synchronous motor, which would allow for the complete zeroing off of reactive draw from the system as measured at the metering point whenever this motor is in service. By decoupling this motor from its load whenever the site is going on an extended non-production run, the motor can still be placed in service as a synchronous condenser; establishing work protection, removing or re-installing the coupling bolts, and preparing the equipment for service can generally be completed in one day.

Whether this is a viable approach for your site involves some careful calculations involving accountants, costing consultants, and other associated stakeholders or parties.

CR

"As iron sharpens iron, so one person sharpens another." [Proverbs 27:17, NIV]

The VAR production of a capacitor bank depends on the terminal voltage applied to the capacitors.
If the tap changer is operated to increase the voltage at the capacitor bank, the VARs will increase. (VARs = Volt, Amps, Reactive)

--------------------
Ohm's law
Not just a good idea;
It's the LAW!

Fer sure; lagging reactive supply from the cap varies as the square of the applied voltage, but that doesn't change the fact that, despite some exceptions, it's usually not practical to operate plant networks outside of nominal band width.

And I'll readily admit that VAR / power factor / reactive control generally isn't cheap, especially if there's a desire to move anywhere beyond granular control; all the more reason to do the number crunching and see how any reactive penalties are assessed, and so forth.

I'd imagine by now that the days when the utility would read the site meters once a month and check and reset the power factor 'drag hand,' billing the site for the peak power factor demand during that billing period , are far behind us; if there are any places that still get billed like that, I'd love to hear about it.

Much more prevalent now are the integrated quadrature meters that are used to bill for reactive energy draw [ or, in rare cases, backfeed ], analogously to the metering of real energy at the POCC. The financial incentive to mitigating poor plant power factor is of course highly dependent on the imperatives that drive the cost; failure to correctly tailor the approach taken to properly match the drivers can be not only very embarrassing but also lead to the loss of employment [ if you work for the company involved ] or the loss of successful bidding on future contracts [ if you as a supplier / designer get a bad rep ].

CR

"As iron sharpens iron, so one person sharpens another." [Proverbs 27:17, NIV]

Respectfully: That was the old demand meters. The drag hand indicated the maximum demand in a billing cycle.
For power factor, a second meter was used. The potential coils of the second meter were fed through a phase shifting transformer and where 90 electrical degrees out of phase.With the phase shifted voltage the meter registered KVAR hours rather than kW hours.
Both meters were read and the kWHrs divided by the root of the sum of the squares of the kWHrs and the KVARHrs.

The Art of Power Factor Correction involved first obtaining one or two years of back electric bills.
An average monthly VARHrs would be determined. Outliers, such as occasional above normal VAR consumption may be ignored.
With a target figure of VARHrs per month in hand, the next issue was placement of PF correction capacitors.
Large loads that operated 24/7 were the first location for caps.
Typically these machines would be double corrected. If 5 KVAR of caps would achieve unit then 10 KVAR of caps would be arranged to switch with the load.
Next would come large motors that may run two shifts for five days. Again, double correction and switched with the motor.
At each step the expected KVARHrs per month would be noted.
The assignments would continue until enough VARHrs were accounted for to balance the monthly VAR consumption.
Note: In those days penalties started at 90% PF. Correcting by switching with big motors and the 10% PF forgiveness took care of almost all of the outliers that had been ignored.
The very infrequent time that the PF average dropped below 90% was so swldom and so little that it wasn't worth trying to address.
Bulk correction was the solution of simply connecting a bank of capacitors on the line.
Bulk correction was known to drive the voltage high during non-production times and more than one plant experienced large numbers of burned out lights.
We did use some bulk correction but only after most of the correction was done with caps switched with the loads.


--------------------
Ohm's law
Not just a good idea;
It's the LAW!

Highly possible I was misled as to the purpose and function of those drag hands; I've occasionally been known to be gullible . . .

Were those ever wired in quadrature and used for the purpose I proposed?

CR

"As iron sharpens iron, so one person sharpens another." [Proverbs 27:17, NIV]

The drag hands were a separate function, not associated with the kW or KVAR metering.
The drag hand was basically driven by a bi-metalic strip that was heated by series heating elements.
Demand penalties are based on I^R heating of the lines and transformers.
As I remember, there was no voltage compensation on the demand metering.
KVA will vary as the voltage varies, but the I^R heating depends on the current alone.
As I recall the time constant of the heaters was about 3 to 6 minutes.
That gave a time to reach full reading of 15 to 30 minutes.
The intent was to match the heating curve of the transformers.

--------------------
Ohm's law
Not just a good idea;
It's the LAW!

I did not know that! Thanks, Bill.

CR

"As iron sharpens iron, so one person sharpens another." [Proverbs 27:17, NIV]

Taha Ahmed -Although the OLTC and the capacitor banks both have some impact on voltage, they have different purposes, I highly doubt that the OLTC is intended to be operated for power factor control.

Power factor is typically only a useful engineering metric only when significant amounts of real power is flowing. When loads/generation are operating at full power, having low power factor requires larger conductors. At low levels of real power flow, power factor does not have a practical engineering impact on conductor sizing. Depending on the design logic of the billing/metering for your specific utility company, there could be illogical impacts of the power factor billing that result in unintended consequences when your generator is offline.

crshears -There are many places with unusual ways to record and bill for reactive power for commercial customers.

One constraint on updating billing methods is the lengthy process of actually updating every meter in the system. When solid state meters were introduced, many utilities simply programmed new solid state meters to match the performance characteristics of older electromechanical meters they were replacing. Utilities basically cannot do a rate redesign until all customers have a meter that be easily reprogrammed. With early versions of automated meter reading, the metering methodology was baked into the initial design of the AMR system.

I have been working on a proposal to redesign our reactive power billing to use new AMI capabilities, so I have been looking for good examples from other utilities. So far, I have not found any utility that it makes sense to emulate.

Quote (bacon4life)

There are many places with unusual ways to record and bill for reactive power for commercial customers

Anecdote Alert
I used to do some work on a small island in the third world.
The local power utility had about 5000 subscribers.
I eventually became the system engineer.
It was a part time, on call job.
I would fly into the island and then travel by boat.
Before I started working for the utility, I had a customer paying penalties for low power factor.
I was able to correct his power factor and get rid of the penalties,
but
I was never able to determine exactly how the power factor was calculated.
One night I was having supper and the manager of the utility was in, drinking his last supper.
He had not been happy at his job and was leaving in the morning, never to return.
I had to ask;
"How did you calculate the power factor penalties for the resort?"
"I could never figure out how to calculate the power factor.
Every month I just guessed!"
This is probably NOT the methodology that you will choose. grin

--------------------
Ohm's law
Not just a good idea;
It's the LAW!

What type of power plant are you thinking of? Most conventional power plants I am familiar with (gas, combined cycle, hydro, diesel) don’t have oltc transformers, they used denenergized tap changers on the generator step up transformers.
The wind plants I have worked at use oltc step up transformers, but the tap changers rarely operate as the the turbines provide reactive support or a separate STATCOM performs this function.

OLTCs are used at the receiving end of transmission lines to compensate for line voltage drop with varying loads.

--------------------
Ohm's law
Not just a good idea;
It's the LAW!

Related thread

https://www.eng-tips.com/viewthread.cfm?qid=466882

Muthu
www.edison.co.in

Terminology I've heard:

ULTC - under load tap changer?

OLTC - off load tap changer? on load tap changer?

OPTC - off potential tap changer?

I take wcaseyharman's point; I've seen live, on-the-fly ULTCs in use in load serving transformers [ 115 kV/230 kV > 14 kV/28 kV/44 kV ], autotransformers [ 115 kV < > 230 kV, 115 kV < > 500 kV, and 230 kV < > 500 kV ], and "quadrature boosters," although we call them phase shifters. Some of the latter owned by our neighbours have two sets of taps in series, one of which is ULTC and the other being an off load but still on potential tap changer.

At the hydraulic and coal-fired generating stations where I worked, there were only ever OPTCs.

CR

"As iron sharpens iron, so one person sharpens another." [Proverbs 27:17, NIV]

At the utility where I work the terminology seems to be:
OLTC: On Load Tap Changer
DETC: De-Energized tap changer

I believe all of transmission and distribution stations in my utility have OLTCs or separate standalone station regulators if the transformer is not equipped with an OLTC.
None of our conventional generation stations are equipped with OLTCs. The transmission provider doesn’t charge for VARs either, that was done away with in the late ‘90s I’ve been told, after the California blackouts of 1996 and 1997 and large generating stations were subsequently required to operate in Automatic voltage control in the US Western Interconnection.
Getting back to the original question, if a power plant were connected to an OLTC transformer and had capacitors, varying the voltage would change the reactive power of the plant load - lower voltages would reduce the contribution of capacitors, and cause motors to potentially draw more reactive power due to higher currents. This seems fairly limited in capability and not very practical in my experience especially since in the plants I work at there aren’t any OLTCs or capacitors and the load current is often very low when the plant is offline, but certainly other plants likely have different characteristics.

The IEEE standards use LTC and DETC. In the 1990's the IEEE standards transitioned away from using the term OLTC for two reasons:
1) In the term OTLC it is unclear if the 'O' stands for OFF or ON.
2) There have been catastrophic cases when folks mistook "off load" as meaning the load was removed by opening the low side breaker. Operating a DETC with the transformer energized results in permanent damage to the transformer. Using the term DETC clarifies that the transformer must be de-energized rather than just unloaded.

Terminology again . . .

Within my organization "off potential" is defined as "disconnected from all sources of electrical energy."


"Isolated" goes further:

"Equipment is isolated when it is separated from all sources of dynamic energy.
"Typically, equipment is isolated by using devices such as valves or electrical switches."


"De-energized" goes further yet:

"Equipment has been de-energized when the electrical or mechanical
hazards associated with it have been removed.
• Electrical equipment has been de-energized when its electrical
energy has been discharged through connection to an effective
ground potential.
• Mechanical equipment has been de-energized when hazards
due to temperature, pressure, chemical substances, gases and
motion have been minimized or, where practical, eliminated by
such measures as:
• operation of valves, gates and dampers,
• opening pipes or equipment to the atmosphere,
• purging, ventilating, or cooling,
• applying brakes and blocking motion, and/or
• discharging loaded springs."

I've come to understand that within my company's operations the "O" means "Off," and ULTC is used to describe an Under Load Tap Changer so as to preclude confusion.

Not saying anybody is right or wrong, only that words matter.

CR

"As iron sharpens iron, so one person sharpens another." [Proverbs 27:17, NIV]

I couldn’t tell you what entailed operating a DETC at my company- we’ve never changed taps since I’ve been here. When we did looks at it for one plant, the substation department was planning to perform a Turns Ratio test after adjustment to verify the integrity of the new tap, which would have required full Lockout Tagout with protective grounds. We didn’t end up doing it because of cost and time.