Richard Clark wrote:


Hi Nick,

Phase is necessarily found in Impedance. As you allow that multiple
generators share a line, they are also across the load as a load if
they do not present the right phase.

As for the "bad idea" of matching, you are appealing to Edison's old
and deliberate misreading of Thevenin. Matching does NOT require a
resistance, this is a mis-read of conjugate matching that follows the
fact (in antennas). It does not drive the need (in power delivery).
Power stations only need perform a Z Match, not a Conjugate Match.
Any form of X is sufficient to accomplish the task and they do it far
simpler through field excitation control.

Hello Richard,

Even with your redefined version of matching, individual generating
stations don't explicitly match to the load reactance or (certainly
not) load resistance. A little generation 101. (This goes a little
beyond the scope of discussion, but I throw it out because I think it's
interesting.):

Generators operate in two modes: Isochronous (single generator
supplying local bus) and parallel (multiple generators in parallel;
connected to a grid).
The operator has two main controls: Steam (or whatever) flow to the
turbine or other driver, and current to the field.

In the isochronous mode, varying steam flow causes the speed of the
generator to change. It also varies the amout of power delivered. In
the parallel mode, the generator can't measurably push the speed of the
grid, so increasing steam flow only increases the electrical power
output.

In the isochronous mode, varying field current changes the terminal
voltage of the generator. In parallel mode, varying field current
can't significantly change grid voltage. But it does change the
reactive power output (MVAR or kVAR) of the generator, as you said.

The normal mode of operation for a large generator is in parallel with
the grid, so the operator is using steam (diesel, water, hamsters,
etc.) to regulate real power output and field current to regulate
reactive power output.

Now some anecdotal stuff about how generators are operated. The system
dispatcher requests individual generators to adjust their power and
VARs to match load. This isn't impedance matching, it's simply
supplying the demand. In the case of VARs, the goal is both to supply
the demand and to equalize voltage across the system, not to cause any
kind of mathematical match between the generator's internal X and the
system's X. Oh yeah, I said earlier that individual generators don't
appreciably affect grid voltage. That's true, but locally they do have
an effect, like tent poles in a big canvas. So the local stations are
both supplying their share of the total reactive load and propping up
voltage in their area. (The operator increases VAR output by taking
his excitation switch to the "raise voltage" position.)

Anyway, I digressed from my anecdotal stuff. At my plant, the
generator puts out 1050 MW 24/7, but MVAR may vary between 0 (or
slightly negative) and 200 MVAR. So we're not matching to any specific
impedance, but supplying load and maintaining voltage.

A story transmission guys like to tell is how they may use open ended
transmission lines as a kind of capacitor bank. Say there's a line 100
miles long from my plant to somewhere that's not needed to carry load.
The system controller might connect it at my plant's end but leave the
breakers open at the far end. A line has both capacitive and inductive
reactance of course, but when unloaded, the capacitive dominates. So
the trick of the trade is to use it to supply reactive MVARs. The
point of the story in this context is that the controller isn't
concerned about SWR on this extremely mismatched line.

Another possibly relevant story. We connect our emergency diesel
generator to the grid for testing and load it to about 3000 kW and
typically from 0 to 100 kVAR. But to fully test the excitation system,
the kVAR is at some point raised to 1400. The point being that the
generator can be operated anywhere within its rating, with no need to
match to any mysterious impedances out there in the world. Makes sense
when you think about it. Who would want a generator that was
constrained to operate at some fixed ratio of real to reactive power?
73--Nick, WA5BDU


73's
Richard Clark, KB7QHC

Thanks very much for the interesting and informative tutorial from
someone in the industry. I have one question:

Nick wrote:
. . .
Another possibly relevant story. We connect our emergency diesel
generator to the grid for testing and load it to about 3000 kW and
typically from 0 to 100 kVAR. But to fully test the excitation system,
the kVAR is at some point raised to 1400. . .

If your customers' loads were, for the sake of argument, purely
resistive as seen at your power plant output, then the voltage and
current would be in phase at that point. But in order to make your
generator produce "reactive power", the voltage and current have to be
forced out of phase at the generator. How is this resolved? Is that
reactive power "delivered" to (actually swapped back and forth between)
other generators in the system -- that is, do the other generators in
the system shift their own phase angles so that the V and I can be at
some angle other than zero at your generator output (and, necessarily,
also at the outputs at other generators in the system) yet in phase at
your customers' loads? Or do you have some local bank of reactance that
you can switch in to feed the "reactive power" back and forth to when
you run this test?

Roy Lewallen, W7EL

Hello Roy,

Good question and one I had considered addressing in my already over long
post. In general "the grid" is viewed as an idealized source or sink of
both real and reactive power. So we can theoretically supply it as much
power as we wish, and supply or take in as much reactive power as we wish.
No reactive load banks needed.

So when I said generation (of both watts and VARs) is matched to demand,
that's not necessarily *exactly* the case when it comes to VARs, as you
guessed. Generators can both supply and absorb them to meet the need, and
the net VAR output doesn't necessarily have to equal whatever the customers
are offering as the load at any given time. BTW, in the power biz, we have
the convention of "supplying", "outgoing", or positive VARs to describe
reactive power out from the generator to a lagging (inductive) load and
incoming, or negative VARs to leading (capacitive) loads. Incidentally,
real power must flow *out* only. We have reverse power (anti-motoring)
relays to trip the unit off line if this rule is broken.

The tendency of generators to exchange VARs when in parallel leads to a
stability problem in excitation control. A slight mismatch in excitation
systems can lead to a huge exchange of VARs and resulting overcurrent. So
excitations system incorporate what is known as a "droop" feature which
essentially provides a negative feedback based on reactive current.
Increased VARs out tends to reduce excitation, stabilizing the system.
Droop is typically switched "off" in isochronous (one generator isolated)
mode. There's an analogous "droop" feature on the governor for speed
control when in parallel.

Not sure if your question included this, but it's interesting to consider
just how a generator produces out of phase current when connected to what
we're essentially considering to be equivalent to an ideal voltage source,
since by definition the generator's terminal voltage must equal that of the
source (grid). As I see it, the key is that the generated voltage, Eg, is n
ot the same as the generator's terminal voltage, Et. There's a drop across
the armature reactance, so Et equals Eq minus that drop. Interesting that
out of phase currents produce drops in phase with Eg ... Well, I thought so
anyway. Current is Et minus Eg divided by Za (armature impedance).
Changing excitation changes the magnitude of Eg (Et is fixed by the grid and
so is an anchor point). By fooling with the phasors, I think you can see
how changing excitation changes the phase angle and therefore controls VARs.

How *power* is controlled is beyond the scope of this discussion (and maybe
of my understanding). But it actually is related to the angle of the
rotor's physical position relative to the rotating field of the armature.
That angle is dependent upon the torque supplied by the driver.

73--Nick, WA5BDU
in Arkansas


"Roy Lewallen" wrote in message
...
Thanks very much for the interesting and informative tutorial from
someone in the industry. I have one question:

Nick wrote:
. . .
Another possibly relevant story. We connect our emergency diesel
generator to the grid for testing and load it to about 3000 kW and
typically from 0 to 100 kVAR. But to fully test the excitation system,
the kVAR is at some point raised to 1400. . .

If your customers' loads were, for the sake of argument, purely
resistive as seen at your power plant output, then the voltage and
current would be in phase at that point. But in order to make your
generator produce "reactive power", the voltage and current have to be
forced out of phase at the generator. How is this resolved? Is that
reactive power "delivered" to (actually swapped back and forth between)
other generators in the system -- that is, do the other generators in
the system shift their own phase angles so that the V and I can be at
some angle other than zero at your generator output (and, necessarily,
also at the outputs at other generators in the system) yet in phase at
your customers' loads? Or do you have some local bank of reactance that
you can switch in to feed the "reactive power" back and forth to when
you run this test?

Roy Lewallen, W7EL

Thanks once again for the excellent explanation. What little I absorbed
in the required year of power systems coursework has pretty much faded
completely out, so I appreciate your taking the time to educate me and
the other readers.

Roy Lewallen, W7EL

Nick Kennedy wrote:
Hello Roy,

Good question and one I had considered addressing in my already over long
post. In general "the grid" is viewed as an idealized source or sink of
both real and reactive power. So we can theoretically supply it as much
power as we wish, and supply or take in as much reactive power as we wish.
No reactive load banks needed.
. . .