How is power sold directly between generator and remote user across different utility entities?

[rockman7892]

This is a question which I've wondered about for quite some time and although I think the answer comes down to commercial agreements as opposed to flow of electrons I was curious to hear from some of the experts here.

As an example I've heard of scenarios where a new generation plant or renewable asset was being built to provide power to a particular customer (say large data center) or load center that may be located in a very remote geography from the generation plant (for example lets say across a state or even multiple states away). There is an example here in FL where I am with a generation plant in the central part of the state being used to alleviate generation and cost in the southern part of the state.

In the example above lets say there are no direct transmission lines to serve load centers directly from generation and thus power must flow across bulk power transmission system to reach its load. Obviously the flow of electrons and power cannot be controlled and thus in above scenarios generation power may flow through multiple utilities, municipals, etc... In this case how exactly does a remote generator impact a customer in a remote location directly when it has to pass through several other utilities or stakeholders?

I'm assuming it has something to do with commercial and bilateral agreements between stakeholders but cant quite put my finder on it. I don't see how a bilateral agreement between two remote locations can stand alone when the power flow from point a to b is impacted by general electrical wholesale market (day ahead trading etc..).

Would love to learn how this process works if anyone has insight.

 

[waross]

Generation in area A.
Consumption in area C.
Area A and area C are separated by area B.
For a charge based on KVAHrs, area A will dump power onto area B's grid. (Note, in this case KVAHrs is used rather than kWHrs.)
Area C will pull power from area B's grid.
Google "Wheeling electricity",

AI generated response;

AI Overview
Learn more…
Wheeling electricity is the process of transporting electricity from one system to another through a third-party network. The utility or wheeling provider is compensated for the service and for any electricity losses that occur during transmission.

 

[crshears]

Bill has definitely started this one off on the right foot.

{quote] "Obviously the flow of electrons and power cannot be controlled . . ." [/quote] . . . Hmm, i guess quoting doesn't work the same way anymore either . . .

Generally true, as power flow normally divides in inverse proportion to the impedance of the interconnected systems, although generation source loading, line loading, series capacitors, and quadrature phase boosters [aka tie line tap changers] may and generally do have profound effects on both real and reactive power flows on an interconnected grid.

Standing market rules and commercial agreements are combined with hourly scheduled transactions to determine who pays how much to who.

 

[jghrist]

Using Waross' example. Consumption will be measured at the Delivery Point between C and B every hour (in my experience, kWh are measured). Someone schedules the expected delivery at the border between B and A, and generation at A. Power is generated at many generators to meet all of the loads at every hour. Customer C will pay A for the scheduled power. If more is metered at A than was scheduled, an adjustment will be made. Customer C will also pay the transmission owners (A to B and B to C) for the kWh plus a set percentage for losses. There may also be charges for peak demand.

 

[waross]

Lest I be understood, I agree with jghrist that Power Bought and Sold will be measured in kWh.
The impact on the system transferring the power will be based on KVAh.
That is, the fees for wheeling the power will be based on KVAh either directly or by kWh with an adjustment factor based on the power factor of the transferred power.

There may also be charges for peak demand.

Yes, I agree here also.

 

[bacon4life]

Although utilities typically charge the end use distribution customer for the impact of apparent power, transmission contract typically just focus on real power transfer. This is because reactive power is predominately supplied locally, with it being rare for significant amounts of reactive power to flow more than 100 miles.

For a load in southern Florida, the majority of reactive power needs of the end use load would be supplied by capacitor banks in southern Florida. Reactive power losses in the transmission system would compensated along the way by intermittent kvar injections along the way.

The actual flow of power is often quite uncorrelated with where one would thing power might flow just based on reading contractual agreements.

 

[waross]

The wheeling company is supplying transmission capacity.
Transmission capacity is based on KVA, not kW.
Given the costs involved in moving large amounts of energy, it may be ingenuous to assume that extra losses due to KVA vs kW are not considered are charged.

My next comment is more a question for CR and others who have appropriate experience.
It is possible to control the PF in and out by varying the voltages with OLTCs.
Then KVA will equal kW.
Deviation from unity PF may then be addressed by penalties that may be greater than a charge based on KVAh.
Question:
Is this done in practice?

 

[crshears]

I was not even peripherally involved in the hourly or other transactions on the grid, but to my understanding what bacon4life wrote is pretty well spot on; true enough, though, that capacity is measured in kVA/MVA, and excessive reactive power flows can limit the transmission of real power on lines and other transmission equipment.

That understood and nevertheless, I have always understood sales, purchases and wheeling costs were based on real power only, with one of my control centre's concomitant frequent tasks being the switching of reactive resources in and out of service so as to both hold system voltages within limits and maximize system transmission capacity.

As to the statement "It is possible to control the PF in and out by varying the voltages with OLTCs" I'd answer, " . . . well, yeah, sort of . . . "

Under Load Tap Changers [ULTCs] can indeed, and do, control power factor, but only on trafos that are in parallel, and they only control the power factor of that trafo itself; the actual instantaneous reactive power flows in any leg or bus of a system are always dictated by the nature of the connected load. Two trafos in parallel will have their ULTCs adjusted so as to control the voltages on either side of them while equalizing reactive flows through them, with LT shunt capacitors deployed as required to both reduce / minimize / optimize transformer reactive power flow-through in concert with supplying [lagging] reactive power back into the HV system to mitigate line voltage drop due to real power loading, as described by bacon4life's summary of "intermittent kvar injections along the way."

Hope this helps.

 

[jghrist]

Transmission reactive costs are normally (in USA) paid by a reactive supply & voltage charge which is calculated by multiplying the transmission company's revenue requirement by the load ratio share (weighted average coincident peak of measured kW divided by the weighted average transmission system peak kW).

The service is defined in Schedule 2 of the Open Access Tariff Agreement (OATT).

 

[crshears]

I reside in, and worked in Ontario, Canada, and never heard of a "reactive supply and voltage charge" . . . but that doesn't mean it isn't out there and I just never learned of it.

Anyone else from ON can weigh in?

 

[waross]

but only on trafos that are in parallel, and they only control the power factor of that trafo itself

Changing the voltage of the supply transformer, which is in parallel with the grid transformers,
Will shift reactive power between the supply transformer and the grid transformers.
Additionally, the receiving transformers transformer may be operated so as to supply leading VARs back into the grid to increase transmission line capacity.
I have seen this concept used on a National Grid.
An entire diesel plant was run at minimum kW and maximum leading KVA/KVAR to supply leading VARs back into the grid and increase transmission line capacity.
Unfortunately I do not know the financial arrangements, hence my query as to if the technique has been used in wheeling situations.

they only control the power factor of that trafo itself

And in so doing control the VARs supplied or drawn from the grid.
eg: supply power at unity PF and draw power at unity PF. Local VARs may be supplied locally.

CR; I respect your knowledge and experience in operations.
However I have had opportunities that may not exist in the systems you controlled.
I have more than once been responsible for smaller plants with multiple diesel sets. (Three or more sets.)
I have been able (at non critical times) to experiment with extreme throttle and excitation settings and watch the resulting variation of Real Power, Power Factor and Output Current.
One time, as an experiment and a learning exercise, we put all the load, a number of large induction motors, on one of three generators and ran it at unity power factor, while the other two sets picked up the VARs. One set could often carry the steady state load, but two or sometimes three sets were needed to handle motor starting.

I do have hands on experience with shifting VARs between sources by voltage adjustment.

 

[crshears]

Hey Bill,

Sounds like we've both had the chance to experiment with the same stuff.

So I reiterate: with two transformers in parallel, you can definitely shift the VARS between them, but you can not control the vectorial sum of reactive power drawn by the load, only the load determines that. I therefore respectfully disagree with your statement that "And in so doing control the VARs supplied or drawn from the grid"; only downstream reactive production with static shunt caps or increased synchronous generation excitation can do that by either matching or, often enough,exceeding the reactive demand of the local load such that the balance flows back out to the grid.

I controlled numerous sites with only one trafo, and in that situation, all tapping the ULTC did was alter the ratio between the grid voltage and the LT bus voltage; monitoring the VAR readings during these operations showed only very slight, non-substantive reactive power flow change through the trafo.

As to "Additionally, the receiving transformers transformer may be operated so as to supply leading VARs back into the grid to increase transmission line capacity.
I have seen this concept used on a National Grid," you're totally correct; however, and again, the lagging VARs pushed back into the HV system will have to be produced somewhere, either with static shunt caps or with increased generator excitation somewhere on the LV side.

I think we're both trying to say the same thing, but we're not saying it the same way . . .

 

[waross]

The under-loaded, over-excited generators supplied the vARs.
Sort of a poor mans synchronous condenser. (A poor utility who have the diesel sets available, but not the money for a new set of synchronous condensers.

But, I think that you have inadvertently answered my question:

Quote CR; the VAR readings during these operations showed only very slight, non-substantive reactive power flow change through the trafo.

My answer is that voltage adjustment is not used because the tap changers do not have enough range to be effective.

 

[bacon4life]

The OATT tariff for my utility for Reactive Supply and Voltage Control service is a rate of $0.14/MWh . The actual power factor of the transaction is not included in our billing data.

The somewhat more complicated rate for BPA starts on page 44 of https://www.bpa.gov/-/media/Aep/rat...final-proposal/BP-16-A-02-AP03-Appendix-C.pdf. Their rate is based on kW of capacity reserved.

 

[bacon4life]

As an anecdote about transformer LTCs, we have connections to two different utilities. We typically operate with a slightly lower transmission voltage that our 115 kV neighbor A, so we often import vars from neighbor A and export the vars to neighbor B at 230 kV. Depending on the position of 230/115 kV LTCs in our system, we regularly change flows at the interchanges points by tens of Mvar. The calculated net reactive load value is only slightly affected by the LTC changes.

LTCs don't generate vars, rather they primarily affect where vars flow. LTCS can consume significant reactive power is situations where transformers on different taps in close physical proximity cause excessive circulating vars. A pair transformers with 10% LTCs and 10% impedance could consume circulating Mvar equal to the transformer nameplate if moved to opposite extreme taps. I have pondered if that feature could be an alternative to inserting transmission reactors at high voltage. However, if one of the transformers tripped, the resulting voltage excursion of 10% would be quite excessive.

 

[davidbeach]

They don't actually have to be all that close, and the taps don't have to be all that different.

Back in the day, when a neighbor common to both of us, was charging for less than ideal power factor, they had a pair of 500/230kV banks, about 42.3 line miles apart, set slightly differently. We'd pay to import "excessive" vars at A and then those vars would flow on our 230kV system to B where we would pay to deliver the same "excessive" vars. They'd then go up the 500/230kV transformer there and flow back to A so that we could buy them back again to allow us to ship them back to B and pay to deliver them there. Rinse, lather, repeat, on an electrical system time frame. Fortunately those var charges stopped quite a while back.

 

[crshears]

Quoting waross: My answer is that voltage adjustment is not used because the tap changers do not have enough range to be effective.

I'm confused by this sentence, Bill; "voltage adjustment is not used" . . to do what? For what purpose? And"to be effective" . . .again, at what?

Again quoting waross:
Changing the voltage of the supply transformer, which is in parallel with the grid transformers,
Will shift reactive power between the supply transformer and the grid transformers.

I'm not grasping the scenario you're describing . . . why would two transformers, operating in parallel, have one described as a supply transformer and one as a grid transformer? Is there a terminology issue here I've never before encountered?

 

[waross]

VARs may be shifted between generators or transformers by adjusting the relative voltages.
My question was whether tap changing could be used to shift VARs so as to avoid wheeling reactive power.
From the responses that I received I understand that it may take a greater voltage shift than is feasible with tap changers to shift enough VARs to be useful.
Also, from bacon4life's information, the voltage excursion in the event of a trip may be excessive.

quote bacon4life: However, if one of the transformers tripped, the resulting voltage excursion of 10% would be quite excessive.

It appears that shifting VARs by voltage adjustment when wheeling is not feasible.

Quote CR: why would two transformers, operating in parallel, have one described as a supply transformer and one as a grid transformer? Is there a terminology issue here I've never before encountered?

In a wheeling situation, the generating system may have a transformer to connect to the wheeling grid.
That is what I meant by the supply transformer.
By grid I meant the wheeling system and its transformers..

 

[LittleInch]

To respond to the original question, this is really an issue on how the electricity grid and commercial systems work in your particular grid system. The grid operator or other entity who is responsible for keeping the grid operational will be told that the generator is supplying X kW or KVA and the consumer at the other end of the grid is taking XkW or KVa and the commercial arrangement is between the two, plus whatever charges the grid operator adds.

As a grid is a pooled mixture of generators and consumers the grid operator is responsible for making the two balance. Where electrons actually go is irrelevant once it enters the grid. The issue that needs to be agreed is how the grid responds if the generator is not supplying power, but the consumer still takes power or vice versa.

Grid operators tend to have emergency powers to continue generation and disconnect large consumers in order to prevent grid failure aka keep the lights on.

A similar thing happens in gas networks with multiple sources and I've seen the Grid code for that and it runs to hundreds of pages. Each party who has a grid connection has a contract which also runs to many pages and lays out what happens in all conceivable circumstances. So a power station e.g. contracts with an oil and gas company to buy X units of gas per day. They input into the gas grid at the nearest point and the power station connects the same. The actual molecules (electrons) that the oil company inserts into the gas grid are almost certainly not the same molecules that the generator burns if there are several input points, but the whole thing balances in the end. Day to day or even hour to hour there is a planned injection of power or gas and also offtakes and the grid operator makes sure the two balance. A dynamic, ever changing situation.

So in very simple terms the grid operator will start with those big known contracted generators and consumers in his plus and minus column. Variable load such as smaller industrial or domestic consumers are estimated by whoever you buy your power from. That entity (lets call it Florida Power company, FPC) then buys electricity generators, starting with the lowest price or fixed base load and then slowly going up in cost.

There are some locations where the grid operator is also the generator and then the consumer just negotiates with the "power company", which is usually some government owned entity.

 

[crshears]

LittleInch: Where electrons actually go is irrelevant once it enters the grid. The issue that needs to be agreed is how the grid responds if the generator is supplying power, but the consumer still takes power or vice versa.

Good observation, Inch; in our case here in Ontario, the Independent Electricity System Operator [IESO] is both a Transmission System Operator and a Balancing Authority, with these two interdependent functions being performed within the same Control Room "by two separate yet equally important groups" à la Law and Order.

Our dealings as Hydro One, an entity that is also registered as a TSO with the North American Electrical Reliability Council [NERC], were exclusively with the TSO part of the IESO; as the owner of the greater portion of the Bulk Electricity System [BES], we were the ones who implemented the directions of the IESO in configuring the actual power system to deal with the "irrelevant" portion of grid operation by manipulating series capacitors, shunt capacitors, System VAR Compensators [SVCs], quadrature phase boosters [aka tie line tap changers], Independent Phase Control Compensators [IPCCs] which are used to correct phase imbalances engendered by inter-circuit coupling in L-O-N-G transmission corridors and the like.