Generator MVARS

T

Thread Starter

THOMPSON

Hi,

I would like to know how VARs affect a generator when connected to a grid. Is it possible to have negative VARs or zero VARs when connected to a grid?
Also how can we control VARs? Thanks.
 
Well, this ought to start another string of posts and only a little bit of contention. From previous posts, the droop speed control thing generated a lot of posts but not too much contention; whenever VArs came up there seemed to be some strong opinions. This should be interesting, and, frankly, I'm completely surprised this hasn't come up before (at least in the three or so years I've been reading and contributing). So, let's get to it!

VArs are typically considered to be positive or negative depending on whether they are Lagging or Leading, respectively, When 0 VArs are "flowing", that is considered to be unity power factor (1.0). (VArs and power factor are related.)

When the excitation of a synchronous generator is is such that the generator terminal voltage is equal to the bus voltage of the grid, then the power factor is 1.0 (unity) and there are 0 VArs "flowing."

When the excitation of a synchronous generator is such that the generator terminal voltage is "higher" than the bus voltage of the grid, then the power factor of the generator will be Lagging (and considered to be positive). This condition is also sometimes referred to as "boosting" the grid voltage, because the synchronous generator is trying to increase the bus voltage of the grid. Depending on the grid, this can be a large or a small effect on grid voltage. To cause the synchronous generator's terminal voltage to be "higher" than the bus voltage of the grid the excitation must be increased. Increasing the excitation causes more DC current to flow in the fiend (rotor) windings; more current means more heat. Heat must be removed; the rotor windings can only tolerate so much heat before the rotor winding insulation is damaged.

Increasing the excitation consumes power; that's power that can't be sold.

When the excitation of a synchronous generator is such that the generator terminal voltage is "lower" than the bus voltage of the grid, then the power factor of the generator will be Leading (and considered to be negative). This condition is also sometimes referred to as "bucking" the grid voltage, because the synchronous generator is trying to decrease the bus voltage of the grid. Depending on the grid, this can be a large or a small effect on grid voltage. To cause the synchronous generator's terminal voltage to be "lower" than the bus voltage of the grid the excitation must be decreased. Decreasing the excitation causes a distortion in the rotating magnetic field of the rotor, which allows uneven stator winding flux (magnetic) distributions which leads to concentrated heating in the stator end-iron. (There are "two" magnetic fields in a synchronous generator: the rotor's and the stator's.) Heat causes problems in many ways, including winding insulation degradation and expansion. Heat must be removed.

(From a generator's perspective, Lagging VArs "feed" a Lagging Load.)

In addition to causing stator end-iron heating, decreasing the rotor magnetic strength can lead to a very catastrophic condition called "slipping a pole" which can cause serious mechanical damage to a generator, the coupling between the generator and its prime move, and the prime mover.

VArs are controlled with excitation.

Lastly, VArs reduce the ability of the generator to produce real power: watts. So, more positive- or more negative VArs (a lower Lagging- or Leading power factor) reduces the ability of the generator to produce watts, which is what most power plants get paid for, not for the VArs that they "produce" or "consume". (There, I said it.)
 
P

Power Hungry

Vars will typically be apparent in the generator as heating but in more extreme cases can create system instability.

Excessive Vars are likely to exceed the thermal capability of the generator and lead to alarm/damage/shutdown on temperature depending on your system arrangement and level of excitation. Google "synchronous capability curve" for more info regarding excitation limits, thermal capacity and stability etc.

A synchronous generator of any size should have excitation limiters to prevent operation outside of machine thermal capability and stability limits.

Vars will also affect the power factor as the overall station/board power factor will be the related to the sum of the watts and the sum of the vars of all units on that bus.

Sharing of Watts with other generators/grid is by controlling generator speed (prime mover) and sharing of Vars is by controlling generator voltage (field excitation) relative to the bus it is connected to.

If you have zero vars you have unity (1.0) power factor. This also means the voltage of the generator exactly matches the voltage of the bus it is conencted to.

Google "Power Triangle" for more info.

If you are importing Vars (as opposed to normal case of exporting) you will have a leading power factor which can be a problem - see possibly useful reference: http://www.cumminspower.com/www/literature/technicalpapers/PT-6001-ImpactofPowerFactorLoads.pdf
 
P

Phil Corso, PE

CSA, having opened the door, I would like to make two comments before addressing your reply:

1) I believe that the questioner Mr. Thompson, as well as others wanting additional information on this overwhelming popular subject, should avail themselves of the 50+ topics in the Control List

2) You are to be commended on your use of the correct term "VARS", and not the oxy-moron "Reactive Power!

Now, on to your reply:

A) You must be very specific as to stated conditions when discussing a generator's operating in parallel with: a) another generator; or b) with a grid!

If a) in parallel with a second generator, then the generator's terminal voltage could rise, or lower, as a result of a change of excitation.

However, if b) in parallel with a "grid", then excitation or speed changes have zero impact on the generator's terminal voltage. Instead they can only affect the generator's internal generated emf! Recall that a grid is a network of generators whose aggregate size is infinite compared to the generator. Hence the grid's
voltage and frequency are unaffected by the action of the generators speed or excitation systems!

B) Lastly, what do you mean by "opinions?

Regards,
Phil Corso ([email protected])
 
Yes; it is possible to have negative VArs, zero VArs, and positive VArs when connected to the grid.

A reactive curve is included in the documentation from the manufacturer of the generator. If not; seek one.

I have no idea how you can control your VAr output. You have not specified your type of control system, your ability to view VArs, or anything else.

As CSA responded: Interesting?
 
If producing or consuming Vars reduces the real power, then why with all the sophiticated controllers and electronics around dont the power plants run at exactly unity power factor. I have often witnessed that our generators run at 0.9 pf. The Exciter has a facility of controlling the pf. Once it is set to pf Control mode, it will try to increase or decrease the excitation to maintain the pf. Should we then keep the pf setpoint to 1 and allow the Exciter to modulate the Generator Excitation and keep the pf unity.

Thanks,
Ivan
 
Exactly; when does 1,2,3,nnnnn generators in parallel become infinite? I believe that a finite number of generators combine to produce a power grid.

I hope I do not upset the balance of things but this type of thinking is why engineers are not given tools.

I apoligize for being so blunt.
 
You raise a very excellent question. It's my personal belief that there is this very prevalent saying about VArs: "They are like foam on beer: They're just there, but they doesn't do anything," that causes many people to have something of a cavalier attitude towards VArs. They know enough to know that VARs should be slightly positive, but that's about all they know. They don't understand the relationship between VArs an power factor, or that power factor is really just a method of expressing the efficiency of the generator with respect to producing "real power".

Most sites I have been to are literally afraid to operate in VAr Control or Power Factor Control. And, if one can convince them to try the modes, they generally have not been tuned properly and any kind of excursion or large deadband just makes the operators extremely nervous. I have tried to tune both control modes when commissioning a new power plant, only to be told it will never be used. Then I've had to return to the plant to tune the functions, and then be told they will never be used.

It's been said by others before here on control.com and I can't agree
more: Power plant operators have the highest inertia of any entity
known to man. They are extremely resistant to change of any kind, and one bad experience means with something they don't understand or which hasn't been properly explained means they will only try something new if forced to. Further, they are creatures of habit like no other creature in the world; they are almost superstitious and fanatical with regard to what they "know" has happened in the past and they way they believe something should or does operate, and no one is going to change their mind even if logic diagrams and piping & instrumentation diagrams say otherwise.

I have been physically threatened by operators who insist their unit never did this or that before, and have been flatly called a liar when I produce documentation that says it couldn't have done this or that. Most power plant operators are capable of steady state operation (heck, my fourteen year old son could probably be a power plant operator in a continuously running, "base load" plant), but when it comes to start-up or shutdown the most common utterance heard in the Control Room is, "It's never done that before!"

Any start-up that gets the unit to desired load is a good start-up and most operators are horrible at being able to detail how their power plant starts up or shuts down, even if there are Standard Operating Procedures in place. It's really, really, really sad and says a lot about the management and ownership of power plants, around the world.

Power plant managers usually have some experience with operations, which makes them subject to some of the same tendencies. Further, power plant operators can be such a difficult bunch to deal with (especially when it comes to "change management" (which is my new favorite term)) that most power plant managers won't even try to suggest doing or trying anything new or different for fear of being killed by the huge whine which they know will follow any such suggestion. And, when faced with upgrading control systems or equipment will generally insist that from an operational standpoint nothing should change, because the operators will complain so frigging much.

So, equipment and controls ain't gonna make any difference, sir. Ignorance and habit will trump common sense and correctness every time, especially in a power plant.

Also, some power plants are required to operate at specific power factors or VAr "levels", though it's the odd plant that will use automation to do so. For all the reasons stated above.
 
Mr. Corso,
Yes, there are many posts on control.com about VArs and more people should use the very powerful search feature of control.com more often than they do for this or any other topic. But, VArs is one of those subjects that is so misunderstood and so difficult to explain and has been explained so poorly by so many people over time that most power plant operators cannot explain something so fundamental and germain to power production.

Sir, I have read several of your brief and nebulous responses to this subject in some of the posts you cited. I have read the exchanges with markvguy. I have not asked for a copy of your paper on the subject, mostly because from what I have read in your posts we have a fundamental disagreement about this subject and I prefer to 'agree to disagree' than to try to offer proof of my experiences without the benefit of data and hard evidence to support my position.

I have read many a section on this topic in many power plant "fundamental" and "operation" and "description" books, some of which I have purchased myself (most of which are a waste of paper and ink when it comes to this subject, and speed regulation and governor control) trying to find a way to explain what I have come to understand through my experiences over the years.

It's just one of those things that I have come to accept that no matter what one says or how one tries to explain, there are people who are going to nod their heads and say, "Yes, I understand," when they don't, or who are going to say, "That's not how it works at all! The angle of the vector and the VA and the load angle..." and they just go off on their mathematical description of this or that which few people can follow much less hope to understand.

It's one of those relative things, relative to the context in which we can understand it or be able to try to explain it to others. It is what it is for each and every one of us, sir.

That's what I meant by opinions, and you understood it exactly correctly.
 
P

Phil Corso, PE

CSA, you are correct! The subject of Syn-gen operation can be simply explained.

In the past most contributers to meaningful discussion had, unfortunately, missed the point But, if you want it all in one place, then I suggest you avail yourself of the document I offered to all List members in '06/'07!

Called "The Physics of ... Armature Reaction", it had 5 goals:

a) Describes Armature Reaction more clearly than hath been presented heretofore (I love lawyer-speak!)

b) Dispels the doubt, misinformation, oxy-morons, and misunderstanding that often crops up in A-list dicussion on the subject!

c) Reduces anomosity (just kidding) about ambiquious and questionable jargon!

d) Eliminates myths, misnomers, omissions, errors, and extraneous word-pairs often used to describe operation of Syn-Gens!

e) Explains how Lagging or Leading VARs are "exported" by a Syn-Gen... not the myriad of terms such as produced, consumed, absorbed, intake, outgo, etc, etc!

Because the paper contains sketches, formulas, and tables, its distribution via Control.com, was ruled out. Instead, I offered an e-mail version
to anyone that wanted it.

So if you want a copy, or anyone else for that matter, contact me!

Now the Caveat: I no longer accept anonymous requests for information or help... something to do with the fact that anonimity breeds a lack of common courtesy! Therefore, anyone wanting the document, must provide a name, affiliation with a company or school, and a location!

Regards,
Phil ([email protected])
 
CTTech,

So, you say that there can only be a pre-determined number of generators connected to any electrical grid. What determines that number? Is it variable?

Are you saying that the load determines the amount of generation which can be connected to the grid? And the number of generators is a function of the output (not the capacity but the total output of all the generators at a given instant in time)? Because, I'll agree with that. Just by adding generation one cannont increase the load on the grid; one will only succeed in increasing the grid frequency. So, if you say the total generation of all the generators connected to a grid is exactly equal to the load of the grid, then connecting another generator in parallel with the existing generators and increasing the output of that generator without taking any other action (reducing the output of any other generator by a similar amount) then the grid frequency will increase. So, one should not be adding generation to a grid without reducing the output of another generator by a similar amount if one wants to maintain grid frequency.

But, I'm not familiar with any arbitrary or finite limit on the number of generators which can be connected to a grid. As long as the total output of the generators connected to the grid doesn't exceed the load of the grid, then the grid frequency will be stable. (I'm not taking into account any transformer or line impedance restrictions or amperage restrictions of any transmission lines or substations; that could definitely have an impact on the amount of generation (and the number of generators taking into account the output and capacity of the total number of generators being connected). I'm just talking about generation versus load, trying to keep it simple for the engineers and the wanna-be-engineers and the think-they're-smarter-than-engineers.

Mr. Corso,

I am remiss in not stating the conditions of my reply: a generator and it's prime mover connected in parallel with other generators on an electrical grid of some size (i.e., not a small 1- or 2 MW grid or even smaller, but a larger grid, like that of a region including several "states" (states being states as in the United States of America or the United States of Mexico or states as in nation states in Europe other geographically- and electrically-connected regions of the world). I'm not talking about generators connected to a common bus with no impedance between them.

I have been places in the world where because of many factors (distance between substations; distance between power plants; line impedance; local loading characteristics) that a change in the generator excitation will have a larger effect on grid voltage on that portion of the grid than will another generator of similar output capability (real and reactive) would have at another location on the same grid. I don't have the data or the mathematical ability to describe it or explain it, but I have seen it with my own eyes on more than one occasion. I've even seen the same plant(s) behave differently at different times of the year (winter versus summer), and when other nearby generation is on- of off-line.

By the way, I am also limiting all of my discussions to synchronous generators (more correctly identified as 'alternators'). None of this induction generator discussion here.
 
Mr. Corso,

I would be more interested to read Ivan's or THOMPSON's review of your paper. As I said before, I will agree to disagree, and since I cannot find the type of explanation and forumulae that I can use to explain my experiences and I lack any hard physical data, I will stay out of the discussion of the principles with you.

I may even be so horribly mistaken in my understanding of the proper physical concept that it would be embarassing. All I know how to do is to relate the principles to concepts I do know and can understand, and when it comes to operation and troubleshooting of power plants my understanding has served me very well over many years.

Lastly, I will say that yours is the only explanation I have ever run across that disagrees with the concept of "reactive power" and VAr flow, which makes me very curious at one level, and very dubious at another. Sometimes, a single person who seems to differ from the horde can have such a keen understanding of a concept or subject that the person is considered to be outside the norm and almost heretical. I have met and come to befriend two such individuals in my lifetime and so I don't discount any beliefs or explanations that I can't absolutely disprove or explain away. Sometimes I regret that position; mostly I learn a lot from the experience. Trying to understand how some people can come to a firmly held belief or understanding can take a long time and a lot of conversation; I have benefitted greatly from learning how people can come to such beliefs and understanding.

But this forum is not the place for such conversations, and because I can't find the clarity I need to be able to support my experiences I can't commit to any further discussion.

I would, still, be very, very, very interested to read anyone's review of Mr. Corso's "The Physics of ... Armature Reaction".
 
CSA, I fully understand your reluctance to unburden yourself of a few questionable habits picked up during your years of experience. I know I still have many!

Reminds me of a story! Three 3 hermits are sitting in a cave; soundlessly meditating life! One day an animal passes the mouth of the cave. A year later, one hermit says, "Didya see the cow passin’ the cave?" A year later, the second hermit responds with, "Tweren’t a cow, t’were a horse!" A year later, the third hermit says, "If you don’t stop this constant bickerin’, I’m gonna leave!"

"Really", as is said in New Yawk, I don’t understand why we have to “agree to disagree!” My offer to you, and others, stands! I’m one that believes "you’re never too old to learn from others", especially if an "other" is one with the passion and fervor you seem to still have for your chosen discipline!

Have a good life!

Sincerely, Phil
 
I apologize to all for not expanding upon my opinions other than screaming “bull”. It is a character flaw. I wish to applaud CSA for presenting exactly what I believe occurs in a major electrical transmission system (grid).

I am a firm believer that the speed of a turbine controls generator frequency otherwise no reason exists for a speed/droop control system. I am a firm believer that generator excitation controls generator terminal voltage otherwise no reason exists for a generator excitation control system. I will stand up and admit that many other variables exist; but many questions submitted to this forum are asking for a basic understanding not the complete explanation of armature reaction. I have found that when assisting others on the understanding of speed control and generator operation it is best to use terms that suit their understanding.

Electricity flows like water. Water cannot flow without a pressure differential (voltage). The flow rate is measured as gallons per minute (USA) (amperes everywhere). The myriad of terms merely assist in the understanding of a concept. Once the concept is understood the student can be subjected to the proper terminology. I do not applaud Mr. Corso in regard to his effort to insist that the majority of operators, technicians, and even the engineers cannot understand unless the jargon is absolutely correct. A VAR is a VAr regardless of the spelling. If another acronym for VAr exists that dispels VAR, I will readily use that. For instance RAM could be Random Access Memory in a computer or Radar Absorbent Material in an F-111 attack bomber.

In response to CSA:
Yes!!! A finite number of generators exist. Only the generators needed to support the current load are operated to produce power (makin’ megawatts). The others remain at rest awaiting their opportunity to contribute; especially fast start GE frame 7B combustion turbines that respond to turbine trips in less than 6 minutes. According to Mr. Corso turbine trips cannot affect frequency or voltage on the grid because excitation and speed changes have zero impact on the infinite grid. The slow start DLN enabled GE frame 7EA will get their chance when the summer temperatures rise and electrical loads increase while we bask in the sun and our air conditioners run continuously.

While laughing out loud; We will bask in the sun and subject maximum loads to our portion of this infinite grid, voltage will not drop and our generators will not be asked to support voltage with VAR control because mathematically our infinite grid will support us. We will also not be subjected to peak usage charges on our electric bills because the VAr does not consume any fuel or other transmission resources.
 
B

Bruce Durdle

A small anecdote to show that you can't always believe the books... A case where power flows in a 220 kV grid network was directly responsible for voltage disturbances. This happened about 35 years ago now.

A 600 MW hydro plant in a remote part of NZ is connected to the rest of the South Island by about 300 km of 220 kV line. There is a substation feeding a city connected into this line at about the midpoint - at the time probably drawing about 70 MW. There were problems reported with voltage swings at the distribution level - caused frequent failures of TV sets, among other effects.

There were no indications of voltage instability at either the remote site of the point of connection to the grid. However, there were definite cycles in the 220 kV voltage with a period of about 5 seconds.

The ultimate cause was traced to governing instability resulting in swings in power flow along the transmission line. Since power flow depends on the angle between voltages at either end, the angular difference was swinging with the power. Even though the voltages at either end were steady, the voltage at the midpoint was going up and down appreciably. Enough to make us believe in phasor theory. (Draw 2 vectors of the same length about 60 degrees apart, and then join the ends with another vector. A line from the centre to the midpoint of the joining line represents the mid-point voltage.) With a remote site connected to an "infinite bus" the same thing could happen.

A few years ago now I had a computer model of the NZ power system to study frequency fluctuations. This modelled the whole system with the mean frequency determined by an overall energy balance and the power variations on individual machines determined by looking at the individual balances at each station. Our system is not an infinite bus by any means as there are one or two stations with unit sizes which are appreciable in terms of the total grid capacity. Falls in frequency from 50 Hz to 48 or below were not uncommon - one result was that the gas turbine on the petrochemical plant I was at used to try and drive the whole North Island back up to 50 Hz, with interesting results on the shear bolts. (I have seen the 2.5 MW set go from 12 MW to 3,5 MW+ over about 2 seconds.)

Bruce
 
M

Michael Griffin

I won't try to interject any opinions about VARs, but to add to Bruce Durdle's anecdote about power transmission, the province of Quebec in Canada has long been unable to connect its grid directly with adjacent regions. They now have back-to-back DC converters (like DC transmission, but the DC bus never leaves the station), but they used to have to disconnect generators from their grid and then reconnect them to an adjacent grid over dedicated transmission lines (or visa versa). Actually, I think they still do this to some extent.

I was told the problem is related in some complex way to their having to transmit so much of their power over very long transmission lines from very large hydro-electric plants (especially Churchill Falls in Labrador and La Grande near Hudson's Bay). They also by the way get instability problems caused by solar storms affecting these same lines.

I suspect that the "infinite grid" theory is a simplifying assumption that works in most situations. The "real" answer probably involves a lot of very complex math that most people don't want to know about.
 
Bruce,

1) It is quite obvious that the system did not meet the definition of an infinite-bus.

2) It is quite obvious that the "computer" model was wrong!

3) Do you remember how the 200-km transmission-line was "modeled?" A short- or a long-line!

4) Do you think you can sent me a simple one-line of the system?

Regards, Phil ([email protected])
 
B
Hi Phil,

The New Zealand grid system does not meet the conditions for an infinite bus. It is divided into 2 halves (the North and South Islands) with a DC interconnection rated at about 600MW at the time I was talking about. Total system load in the North Island was about 4,000 MW: the load in the South Island about 2,000 MW. Pretty well all generation at that stage was hydro - mostly run-of-river in the North, with the majority being on one river and with a small geographic spread. One or two small generating stations were situated remotely and connected by relatively weak links. The major load is Auckland at the north of the North Island: the DC link is connected in to the NI grip near Wellington at the southern tip. So when the DC link dropped a pole (which was about monthly at the time) there was a short-term loss of about 15% of inflow to the north system, lasting for a couple of seconds till the mercury arc rectifiers re-ignited (or whatever - I had nothing to do with that system.) As a result the whole system slowed down as kinetic energy from the machines was used to make up the difference - hence the frequency dips. The model I wrote did a good job of predicting the magnitude and duration of these effects, including what happened when some additional large thermal stations were added in the 70's and 80's. So there can't have been too much wrong with it.

The effects I described on the 200 km link was modelled in the best way - they were observed on the real system. Unfortunately, I cannot point you to a single-line diagram of the system as the fragmentation of the electrical generation and transmission systems means that the info is spread over a number of organisations.

Bruce
 
CSA and CCTech, I don't understand your position(s), i.e., Critics w/o Critiques! Therefore, following is an abridged copy of the paper presented in January 2007, but without the items that seem to have you stupified such as illustrations, tables, formulae, phasors, or vectors:

1. Introduction. This paper has four goals that are listed below:

(a) Describe Armature Reaction more clearly than hath been presented heretofore (I love lawyer-speak.)

(b) Dispel doubt, misinformation, and misunderstanding that have cropped up in related A-List topics.

(c) Reduce animosity (just kidding) about questionable or ambiguous jargon.

(d) Eliminate myths, misnomers, and omissions. Adjectives describing Armature Reaction are plentiful, some even inventive, but most miss the point! Here are some pairs that were culled from A-List and Off-List responses: adds-subtracts; additive-subtractive; augments-negates; crowded-expanded; decreases-increases; fights-gives up; overcomes-replaces; overtakes-replenishes; magnetize-demagnetize; support-oppose; strengthen-weaken; and swell-shrink. There have been and certainly will be others! Thus far, no-one has used adjectives such as: encourage; discourage; thwart; or tweak! I hope this paper will curtail (hmm, a synonym I hadn’t noticed earlier) the seemingly growing list of adjectives.

2. Definitions: Official; Time-Proven; and Preferred [Ref. A & B]. IEEE Std 100 defines armature reaction as: "The magnetomotive force due to armature winding current." Rather sparse! Karapetoff’s definition in 1911 was: "When carrying loads armature-current being a source of mmf, modifies the flux created by the field coils, thus influencing the performance of the machine." I prefer, "Armature-current mmf modifies the field-current mmf so that the resultant armature-reaction mmf, changes the machine’s generated emf."

3. Synchronous Generator Armature Reaction (General Theory) [Ref. C & D]. Let’s start with the basics for a generator delivering power to an isolated load. The generator has two magnetic structures, one the stator (fixed in space), and the other the rotor (driven by a prime-mover). They are separated by an annular space called the air-gap (regardless of coolant, for those ready to pounce.) Each structure carries windings that are linked by a mutual flux crossing the air-gap, and as a result a generated-emf is produced in the stator. Current in the rotor field-coil produces a rotating magnetic-field called field-flux. When a generator is loaded, current in the stator-winding produces its own synchronously rotating magnetic-field called armature-flux. Two observations can be made: 1) each mmf has magnitude and direction; and 2) they exist independently of one another. When the two fluxes combine the resultant air-gap flux changes generated-emf. And, because field-current is a constant and stator-current a variable, then armature-flux is said to affe ct field-flux. The interaction is called Armature Reaction!

Digressing for a moment... an analogy to the above is the ocean surf’s undertow... while the surface current can be seen moving towards the beach an unseen undersea current is also moving, but in a direction away from the beach! When the two currents combine the resultant current speed and direction determine a swimmer’s fate. The effects of undertow and armature reaction are similar, differing only in dimensional units, that is, the former uses physical quantities, the latter magnetic quantities.

The unit-dimension for mmf is ampere-turns. Thus, when the statement "the field... opposes... aides…... shrinks... etc" is made, then, what actually occurs is an increase (or decrease) of the air-gap’s total ampere-turns. Thus, its mmf can be treated as a vector, i.e., having magnitude and direction, but strongly influenced b the nature of the load.

For a lagging-current load, armature-mmf subtracts ampere-turns from the field-mmf, thus weakening air-gap flux! Conversely, for a leading-current load, armature-mmf adds ampere-turns to the field-mmf, thus strengthening air-gap flux!

A seemingly complex process? Yes! But not if one thinks of the process as a chain reaction: armature-flux modifies field-flux; resulting in an air-gap flux change; changing generated-emf; culminating in a change of terminal voltage; requiring corrective action by the Automatic Voltage Regulator (AVR)!

In general, for cylindrical-rotor machines the modification appears as shift in pattern, while for salient-pole machines there is pattern distortion. The three magnetic-fluxes can be identified by their associated mmf vectors: f is field-flux; a is armature-flux; and r is resultant airgap-flux.

8. Conclusions. Assuming that the terminal voltage is constant, then the effects of load power-factor on armature reaction can now summarized:

• Unity Power-Factor Load. A unity power-factor load, i.e., line-current in-phase with terminal voltage, causes the armature emf to weaken the air-gap flux produced by the field alone! Field-current (excitation) must be increased to maintain terminal voltage!

• Lagging Power-Factor Load. A lagging power-factor load, i.e., line-current lags terminal voltage, causes the armature emf to weaken the air-gap flux produced by field coils alone! Field-current (excitation) must be increased to maintain terminal voltage! (Note: if connected to an infinite-bus system, the machine is said to be over-excited, and it delivers or exports lagging kVAr!)

• Leading Power-Factor Load. A leading power-factor load, i.e., line-current leads terminal voltage, causes the armature emf to strengthen the airgap-flux produced by the field coil alone! Field-current (excitation) must be decreased to maintain terminal voltage! (Note: if connected to an infinite-bus system, the machine is said to be under-excited, and it delivers or exports leading kVAr!)

10. Addressing Incorrect A-List Responses Related to Armature Reaction. Several A-List posters have advanced theories about armature reaction that are plain wrong or confusing. Some fellow posters introduced myths; others mis-name the process of kVAr exchange between a generator and another power source or system; still others, have used incorrect unit-dimensions of electrical parameters. I also omitted an important observation related to end-connection effects. Following are my comments concerning the most noteworthy discrepancies:

• Armature Reaction causes a change in field-current! I am sure that what the A-List contributor observed was the corrective action of the AVR responding to the terminal voltage change!

• Armature Reaction under-excites or over-excites the field! IEEE Standard 100 does not define the term. Neither are there definitions for over-excitation and under-excitation. However, the research done for this paper indicates that, except for synchronous condensers, the terms under-excite and over-excite are in discussions related to interconnected generators, such as those operating in parallel, or those connected to an infinite-bus. In addition, the terms are used more frequently describing synchronous motor operation than for synchronous generator operation!

• Armature Reaction causes the field-flux to modify armature-flux! Just the reverse is true. The field-flux is fixed, but armature-flux is proportional to armature-current. Therefore, it is armature-flux that modifies field-flux!

• Operation in parallel with other sources! In my opinion a synchronous generator does not absorb, or consume, or import, or receive, or take-in, or produce, reactive power. Then, for consistency, the author suggests that the terms listed above, as well as reactive power, be eliminated. Instead, substitute the expression that the generator delivers or exports lagging or leading kVAr! (NOTE: this recommendation does not preclude anyone from using terms they are familiar with!)

• This one is mea-culpa! My response to the thread "Alternator Running in Leading kVAr" addressed the fact that low-pf leading current operation is more deleterious for armature end-connections than low-pf lagging current operation. I presented (correctly) the fact that increased stator-current results in a dangerous increase in the stator conductors’ (in-slot) length. However, I failed to include a crucial point. That is, the heat present in the stator winding end-connection is disproportionately higher than that of the portion embedded in the stator core-slot, because their radiating surfaces are different, as well as the manner in which they are cooled!

• Which unit-dimension is to be used: a) KVAr; b) KVAR; c) kVAR; or d) kVAr? Using SI-Units, and multiples and prefixes for SI-Units, then d) kVAr is the correct term! An-aside, SI-Units were approved by the US Congress in 1866. However, stubberness (sound familiar) on the part of our scientists, engineering, and tech communities has prevented general use in the USA! Admittedly, there is a problem if inductive kVAr and capacitive kVAr are to be differentiated in the same discussion! Then, I suggest the use of kVAr(i) and kVAr(c), respectively! One last point on the subject of terminology; the "s" often used to denote multiples of a prarticular dimensional unit should be dropped.

CSA and CCTech, you both must agree, that now, you have something to critique!

Phil
 
Splitting hairs, and very fine ones at that. Producing/consuming vs. delivering or exporting. I have almost no issues with the rest of the abridged version, but I do take exception to this minute hair-splitting.

I'm still interested in hearing other's opinions of the paper and how informative and useful it is.

And, I'm not exactly clear how this explains VArs, or kVArs, which is what this thread was about (I think!). Nobody asked about armature reaction; the question, as I recall it, was what was the effect of VARs (sic) on the generator, and explaining armature reaction doesn't explain why kVArs are (need to be) produced or delivered or exported or what the effects of producing or delivering or exporting them is. There is a little bit about the effects of heating, but what about the effects on generation (power production) of producing/consuming or delivering or exporting lagging or leading kVArs? Where's the discussion of the reactive capability curve which depicts what happens when the unit is producing/consuming or delivering or exporting lagging or leading kVArs?

I'm just constantly looking for a utilitarian explanation of (k)VArs that most anyone can understand and might even be able to be used to explain it to others so that they can understand.

Lastly, I am not stubbern; stubborn, yes. Stubbern, no.
 
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