Loss Allocation to multiple resources on a bus.

[LJP1]

Looking for advice and recommendations on properly allocating KW and KVAR losses across multiple transformers sharing a transmission line and then further allocate each transformer line loss share to its related resources/feeders under each transformer.

Assumptions -
1. Three transformers connect to common T-line. Each transformer has both PV and BESS resource feeders on low side.
A. PV operates +/-.95 PF, generation only.
B. BESS can operate +/-.5 PF, discharge or charge.
2. Revenue Meters are placed at each key point to capture real-time Current, KVA, PF, KW and KVAR to perform loss calculations and allocations as needed. i.e Meters at each resource feeder bus connection, at each high-side transformer bus connection, and at far end of line (point of delivery).
3. Resources -

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A. Any PV may be generating or idle depending on maintenance or night time.

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B. Any BESS may be discharging or charging KW and/or sourcing +/- VARs.

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C. With active VARs requirements, allocation of VAR losses for all resources to be applied through separate allocation calc than KW loss allocation.
4. Losses -

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A. KW and KVAR line losses are determined by the difference of the Line meter and the summed High-side meters.

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B. Each transformer KW and KVAR losses are determined by the difference of its High-side meter and its summed Low-side resource meters.
5. Resources are to share associated accumulated losses. Exception if net flow through transformer to line is + (Delivered to load), BESS is fully charging and will be assigned all losses.

Questions -
1. What is best method to allocate both KW and KVAR line losses to each Transformer, using any combination of Currents, KVA, PF, KW and KVAR from available meters?
2. Each transformer's line loss is determine by solution to above Q1. Then line loss result is combined with transformer losses, with result to be total losses to be allocated to Resources. What is best method to allocate losses both KW and KVAR total losses to each Resource, using any combination of Currents, KVA, PF, KW and KVAR from available meters?

 

[bacon4life]

The complexity of the this situation makes me worry that the calculations would need frequent updating. Many entities use system wide loss factors rather than attempting to have extremely detailed loss calculations for each piece of networked equipment.

Typically transformer loss calculations are based on factory test reports rather than comparing two revenue meters. The loss compensation calculation can be either programmed into the meter, into the utility accounting system on a per transformer basis, or into the utility accounting system on a system wide basis.

Taking the difference of two meters is problematic since the error in meter measurement is of similar magnitude as the transformer losses. As an example, I have a 240 MVA transformer that has load losses of 0.24 MW. A typical revenue meter has an allowed error of 0.3%, which is 0.72 MW. Assuming exactly 240 MW is entering from the generator with maximum allowable meter error, the high side meter could read 240.48 MW and the generator side could read 239.28 MW. Obviously the the transformer does not create 1.2 MW of power.

Meters tend to have low accuracy at light loads, so the accuracy of measuring standby losses in on the PV may be quite low at night.

What is the driver for needing to allocate reactive losses between generators? In my region there has a been a move toward requiring generators to provide voltage control services rather than attempting to bill for reactive power.

If you have detailed allocation method, consider different methodologies for excitation losses versus load losses. Even though the PV is shut down at night, the transformer will still be drawing excitation losses during all hours.

 

[davidbeach]

Bacon's example calls to mind the adage that a person with one watch know exactly what time it is, but the person with two watches is never quite sure.

Meter the PV and the BESS separately as close to them as possible. Use that data for the tax credits and other incentives. Then do the revenue measuring at the point of interconnection. Add the PV and BESS totals to get the share of each and then apply those shares to the total from the interchange meter.

I’ll see your silver lining and raise you two black clouds. - Protection Operations

 

[LJP1]

Bacon4life, (BTW nice handle )

Thank you for your reply. I have replied to your comments and question below. With that said, do you have thoughts/suggestions on allocation methods for KW and KVAR losses using combinations of Current, KVA, PF, KW and KVAR from each meter?

The complexity of the this situation makes me worry that the calculations would need frequent updating. Many entities use system wide loss factors rather than attempting to have extremely detailed loss calculations for each piece of networked equipment. (LJP1 - Yes...Complicated. The real-time loss calcs programming is required by the ISO to be done in the revenue meter, which is the "regulated/sealed/secure" device. One of the high-side meter serves as the main calculating meter pulling data from the other high-side meter and its resource meters. It makes the calcs and then redistributes the associated loss results back to each appropriate meter. Depending on the full number of calcs, the process update cycle time is between 5-10 secs.)

Typically transformer loss calculations are based on factory test reports rather than comparing two revenue meters. The loss compensation calculation can be either programmed into the meter, into the utility accounting system on a per transformer basis, or into the utility accounting system on a system wide basis. (LJP1 - see above).

Taking the difference of two meters is problematic since the error in meter measurement is of similar magnitude as the transformer losses. As an example, I have a 240 MVA transformer that has load losses of 0.24 MW. A typical revenue meter has an allowed error of 0.3%, which is 0.72 MW. Assuming exactly 240 MW is entering from the generator with maximum allowable meter error, the high side meter could read 240.48 MW and the generator side could read 239.28 MW. Obviously the the transformer does not create 1.2 MW of power. (LJP1- Noted. But would this error average out over the interval [5 min, 15min or hr]? With the focus on determining losses attributable to each low side resource, how would transformer loss compensation calcs based on the sum of low-side resource meter reading and an outboard accounting engine be more accurate?)

Meters tend to have low accuracy at light loads, so the accuracy of measuring standby losses in on the PV may be quite low at night. (LJP1- Noted.)

What is the driver for needing to allocate reactive losses between generators? In my region there has a been a move toward requiring generators to provide voltage control services rather than attempting to bill for reactive power. (LJP1- While there has been no definitive direction by the ISO to use VARs in a business accounting process, I wanted to "future proof" the design by applying similar allocation methodology used for KW losses for KVAR losses as well. Further more, I have to believe with the BESS cranking out VARs for voltage control, that it has to impact the over all flow through the transformer and line. I would just like to give credit (good or bad) where credit is due.)

If you have detailed allocation method, consider different methodologies for excitation losses versus load losses. Even though the PV is shut down at night, the transformer will still be drawing excitation losses during all hours. (LJP1- Noted.)

 

[LJP1]

davidbeach,

What would be the most appropriate method to allocate the line and transformer losses back down the line to the difference sources?
Proportion of I^2s for both KW and KVAR losses?
Proportion of KW^2s value for KW Losses?
Proportion of KVAR^2 values for KVAR Losses?
Function of KVA proportion, Voltage and PF?

 

[waross]

Losses in kW; Will this work?
(Secondary current times secondary transformer resistance) plus (primary current times primary transformer resistance).
For greater accuracy you may add a slight exponential factor to the current to compensate for greater resistance at greater loads.
If you are also concerned with line losses, the same method may be used to calculate line losses.
--------------------
Ohm's law
Not just a good idea;
It's the LAW!

 

[bacon4life]

Which ISO are you in?

?

Meter errors are unlikely to average out to zero. As a specific example, I have one GSU transformer that always appears to magically be creating power because the measurement of power flowing out is larger than the measurement of power flowing in.

With metering, is easy use lots of extremely precise components to create an overall meter-to-revenue system that fails to be accurate.

It is also important to use each meter within it's specified accuracy range. In the transformer factory the manufacturer typically uses an extremely precise meter to measure transformer parameters. At the factory they separately measure load versus no load losses, so they can measure the values very precisely. For my 240 MVA transformer, the losses measured in the factory are accurate to better than +/- 2 kW. The losses that can be calculated based on those transformer parameters are probably accurate to better than +/- 20 kW. The losses calculated subtracting by subtracting two revenue meters rated 240 MW could be off by up to +/- 1,440 kW.

 

[LJP1]

CAISO

 

[davidbeach]

Yeah, but those losses were measured at one random ambient temperature and then corrected to a different temperature and that’s what went into the test report.

I’ll see your silver lining and raise you two black clouds. - Protection Operations

 

[bacon4life]

LDP1-Do you have a link to the CAISO document you are trying implement? Section E of

https://www.caiso.com/Documents/MeteringProtocolApendixA-G_31-Aug-04.pdf

requires transformer loss compensation to be based on using the test report parameters. This document does not appear to include provisions for allocating transformer losses between multiple generators on a transformer. Perhaps CAISO has more recent document with different provisions?

David-Are you suggesting that there is a better accuracy alternative compared to using the test report to enter loss correction values into the meter? I agree the actual operating temperature of the transformer in the field will not match the test report conditions, so there will be some amount of error in the load loss calculations. The temperature coefficients of stray losses and I^2*R losses are opposite signs, so the overall increase is losses for transformers at higher temperature operation is not as significant as for cables operating at high temperatures.

 

[davidbeach]

No, not suggesting that there's a better method, just that there's some inherent uncertainty. Just like trying to get good fault data; it's calculated on an impedance that probably isn't the instantaneous impedance of the transformer because the resistive component is based on a temperature that isn't where the transformer is operating and likely also based on a ratio that also isn't where the transformer is operating. But we can get close enough and the losses can be measured close enough. And close enough, can as you showed, even include having the wrong sign on the result. And, of course, as everybody knows, it doesn't matter how good the meter is if it's getting its current from protection CTs.

I’ll see your silver lining and raise you two black clouds. - Protection Operations