# What makes a generator increase load

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#### SGS

Why there is always a consistent voltage of 11 kV in most of the generators up to 100 MW?

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#### SGS

"Because of the torque angle increase the phase angle between the voltage impressed on the stator from the grid, and the voltage impressed on the stator from the (rotor) field is also increased. The resolved sum of these voltage vectors results in a higher net voltage. This higher 'net' voltage is what draws a greater current in the stator."

#### CSA

SGS,

These "torque angles" are the result of loading a synchronous generator and it's prime mover--NOT the reason for loading. It's very important to understand that these are just mathematician's and physicist's ways of explaining and modeling and predicting what's happening in the generator.

And, when it comes to explaining how generators "work" to people who don't have knowledge of vectors and can't visualize torque angles (because they can't be seen with the naked eye--or even with a microscope!) they are pretty darn confusing.

Yes; there are lots of electrical "shifts" going on between electrical fields in a synchronous generator, but it's important to understand that the generator is just a device for converting torque into amperes--and that electric motors (which are driven by generators!!!) are devices for converting amperes into torque. To load a generator (synchronous generator) one has to apply more torque to the generator rotor. The change in torque angles and reactions of this or that type are the <b><i>RESULT</b></i> of applying more torque from the prime mover driving the generator. And trying to explain that loading a generator by referring to the invisible torque angle is virtually impossible unless one is well-versed in physics and electric fundamentals.

Torque angle isn't something that power plant operators or technicians (or even most supervisors and plant managers) understand or even need to know to be able to operate a plant properly and efficiently. Generator designers and physicists and mathematicians need to know this stuff, not operators and technicians and their supervisors and managers.

Remember: At it's simplest, a synchronous generator (any kind of electrical generator) is just a device for converting torque into amperes. And the electric motors and electric devices at the other end of the wires the amperes are "pumped" into convert amperes back into torque (useful work driving pumps and fans and elevators and such).

And, on a personal note, I just don't understand why people have no problem understanding that electric motors convert amperes into torque, but they have huge problems understanding that the amperes come from generators that convert torque into amperes. Generators are really very unintelligent devices--contrary to popular belief. Increase the amount of torque being provided to the generator, and the amount of amperes coming out of the generator will increase (presuming the grid the generator is connected to is being properly regulated and supervised). Decrease the amount of torque being provided to the generator and the amount of amperes coming out of the generator will decrease. At it's simplest--that's what a generator does.

The control system is really all about controlling the amount of torque being provided to the generator by the prime mover driving the generator: the turbine, or the reciprocating engine. The production of torque (which isn't directly measured!) is controlled by controlling the amount of steam or water or fuel entering the turbine, or the angle of the wind turbine blades, or the amount of fuel being injected into the reciprocating engine. The generator then converts that torque into amperes that are transmitted via wires to loads (electric motors and electric devices) that then convert the amperes back into torque to do useful work (pump water, move air or refrigerant, produce light or heat, etc.).

Changing torque angles and voltage reactions are all ways to measure how much torque is being converted to amperes, or how to predict how much torque can be converted to amperes, or how to test students on being able to use geometry and calculus. But power plant operators and technicians and their supervisors and technicians don't need to know--nor can they see--changing torque angles and voltage reactions. That's not the reason for how generators are loaded (or unloaded)--that's the justification for how they do what they do: convert torque into amperes.

#### CSA

SGS,

> Why there is always a consistent voltage of 11 kV in most of the generators up to 100 MW?

Would it surprise you to know that in many parts of the world where 60 Hz generators are used the most common generator terminal voltage is 13.8 KV?

The reason these voltages are common are because they have become common over decades and decades of use. Many transformers are built for specific input/output voltages, and many generator manufacturers have standardized on certain generator terminal voltage ratings. 11 KV is one; 13.8 KV is another. It's all about economics and preference and adaptation, and that's how things tend to become "standards"--by adoption rather than by decree. There are usually many economic factors that also factor into these kinds of decisions (sizes of copper bus bars; size and number of slots in the generator stator; size of generator field; etc.).

And, in order to produce generators more "economically" it's easier for manufacturers to produce a "standard" voltage rating, rather than having to produce a different voltage rating each time the generator is produced. This makes manufacturing simpler, and reduces the cost to purchasers.

The thing that should be noted here is that the generator terminal voltage is usually relatively stable during normal operation--that is, it doesn't change by very much (usually less than plus- or minus 5% of rated). Combine that with the fact that synchronous generator speeds are fixed (on well-regulated and supervised grids) and you have the necessary conditions for the production and transmission of torque, ..., er, ..., uh, ... amperes/watts/electric power.

Hope this helps!

C

#### C.D.Elkunchwar

I have gone through very interesting and informative interaction on the subject matter. I am putting up different angle trying to explain the phenomenon.

Let us consider the generator is connected to the grid with a resistive load of say 100MW. the direction and magnitude of the armature current would be such that the magnetic forces created because of interaction of two magnetic fields would always oppose to the cause which has produced them. So these (attractive and repulsive) forces will oppose the rotor from turning anti-clockwise. The turbine has to produce that much torque so as to overcome the effect of these forces and losses (mainly frictional and wind age losses) so that speed of the rotor would remain same. To increase the load on generator to say 120 MW, the steam flow is increased as per set point and governor valve opening, the turbine produces additional torque. Through the magnetic circuit this added energy is transferred from rotor shaft to the electric circuit and as AVR controls the voltage, and thus no change in power factor, stator current increases and hence the MW. The increased current would create more stronger forces which would oppose the rotor from turning anticlockwise and increase in the load angle. System frequency will always respond to the demand supply gap and number of poles (salient or non salient) would be fixed. The effect of large electromagnetic forces in severe armature reaction opposing the rotor turning should be taken into consideration

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#### Emil Sagal

Thank you for a detailed explanation. Please make it clear whether or not the PF of a synchronous steam generator is equal 1. Also, if utility demands leading or lagging PF then is it possible to do so by changing a phase angle? If it is possible then where does it take place? IN the rotor's control circuitry or somewhere else?

[email protected]

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#### Jlforrester

how do you increase the reactive output of a synchronous steam turbine generator?

#### CSA

> how do you increase the reactive output of a synchronous steam turbine generator?

The same way you increase the reactive output of any synchronous generator: By varying the excitation.

If the excitation is equal to the amount required to make the generator terminal voltage equal to the bus voltage of the grid it is synchronized to the reactive current will be zero.

If the excitation is increased above that required to maintain generator terminal voltage equal to grid voltage--in other words one is trying to "boost" the grid voltage--the reactive current will increase in the lagging direction (and the power factor will decrease below 1.0 in the lagging direction).

If the excitation is decreased below that required to maintain generator terminal voltage equal to grid voltage--in other words one is trying to "buck" the grid voltage--the reactive current will increase in the leading direction (and the power factor will decrease below 1.0 in the leading direction).

The above presumes you are not asking how to increase the reactive current rating of a synchronous generator--just how to change the reactive current flowing in the generator stator windings.

#### Chemsouhd

Well explained CSA as always,

TNR/TNH Error.....etc. I suppose you're talking about GT simple cycle. Could you please explain the speed droop in Combined cycle? As we have 9FB in CC with A15 ST. here we're talking about two (2) prime mover both of them apply a torque on the generator.

I remarked that at Base load TNR is about 102% and to get more amperes not just increase fuel on GT also increase steam on the ST. Could you explain please how to share needed load (torque) between G/ST?

#### CSA

Chemsouhd,

So, you have a single-shaft "STAG", STeam- And Gas Turbines driving a single generator?

To be quite honest, I have very little experience with such arrangements. The thing to remember about steam turbines in combined cycle applications (multiple-shaft or single-shaft) is this (and it's VERY IMPORTANT): The load on the steam turbine is primarily and mostly a function of gas turbine exhaust heat and flow-rate. On MOST combined cycle steam turbines, once the steam turbine reaches a certain load (determined by the manufacturer) the steam turbine control valves are driven to the full ("wide") open position. This means that the load being produced by the steam turbine will be strictly a function of the amount of steam being produced as a result of the gas turbine exhaust (heat and flow-rate). There's really no other efficient way to operate the steam turbine in combined cycle applications, because the "firing rate" of the steam generator (the Heat Recover Steam Generator--the HRSG) is not a controllable parameter because it's dependent on the gas turbine load, exhaust temperature and exhaust flow-rate. (Yes--there are some HRSGs which are "fired" (Duct Burners; Auxiliary Firing; etc.) and are controlled, but usually that's only done to augment gas turbine exhaust heat and flow and usually only at higher gas turbine loads (not always, but usually).

So, the steam turbine control valves are driven fully open and whatever steam at whatever temperature and pressure is currently being produced by the HRSG flows through the steam turbine to produce torque which is converted to amperes by the generator (in either multi- or single-shaft configuration).

The steam turbine is also usually only half the rating of the gas turbine (or roughly equal to the rating of one of two gas turbines in a two-on-one combined cycle application, where there are two gas turbines, each exhausting into their own HRSG to produce steam, and the steam flows of both HRSGs are directed to one steam turbine). (The rule of thumb is that the exhaust heat from one gas turbine will produce approximately 0.5 MW of electrical power for every 1.0 MW of gas turbine electrical power being produced.) And, because it's smaller than the gas turbine(s) in a combined cycle plant it can't really have much of an effect on frequency or load of the gas turbine(s), especially since it's load is a function of the gas turbine exhaust temperature and flow-rate.

I'm absolutely CERTAIN that GE Belfort (the GE facility that has responsibility for GE-design Frame 9 heavy duty gas turbine control philosophy) has some extremely and unnecessarily convoluted control scheme for the gas- and steam turbines in a single-shaft, STAG, plant. No uncertainty whatsoever. And, I would be hard-pressed to even try to understand or explain the scheme to anyone, much less understand it myself. Other packagers of GE-design heavy duty gas turbines probably have some scheme they have devised which is not nearly as complicated and yet still works well, but GE Belfort could NEVER do things simply when it could be made to be unnecessarily complicated.

I would think that an operator would be trained to understand the relationship between GT load and ST load (the ST load being approximately one-half the GT load for most operating conditions, with the exception of fired HRSGs) and would take that into account. I know that some STAG applications also use some steam "bypass" schemes to direct a portion of the steam directly to the condenser in certain conditions, which could be how some loads are are "controlled"--but bypassing steam to the condenser is usually considered inefficient.

But, I am also fairly confident that the GT turbine control system (especially if it's a Mark* system) still uses Droop speed control for Part Load fuel/load control. It's usually a requirement for synchronization to a grid because Droop speed control is the control mode that allows multiple generators to operate stably with each other and to appear as one large generator to the electrical transmission and distribution system (the "load"--the sum of all the motors and lights and televisions and computers and computer monitors and tea kettles).

You would need to provide a LOT MORE DATA than you have in order for anyone to make any comment about why TNR might be 102% at "Base Load;" I presume you are referring to the electrical load of the generator versus the GT rating? Because, as was said, for un-fired HRSGs the steam turbine rating would be approximately one-third of the total rating of the combined GT and ST. But, again--no basis for the statement and no context have been provided so it's impossible to say anything with any degree of certainty in response.

#### otised

CSA,

Controls for the steam turbine and HRSG on a single shaft 9FB with an A15 ST were most likely designed in Schenectady. The GT controls could have been either Belfort or Greenville, depending on when this plant was built. The steam turbine controls would have been by Steam Turbine in Schenectady, and the HRSG and BOP controls and overall plant would have been by Power Plant Engineering in Schenectady.
That said, your overall description of the load control is accurate. The gas turbine and its waste heat is the source of all energy, the steam turbine "eats" all the steam produced by the HRSG. Supplemental firing of the HRSG was occasionally done, though more frequently on multi-shaft STAG units than single-shaft. It was usually a requirement that the gas turbine be at or near base load before the supplemental firing was initiated.

The only time the steam turbine does not consume all the steam produced by the HRSG is during startup, while the steam bypasses are in operation.

#### Chemsouhd

FYI Sirs, We're talking STAG Single shaft, without extra firing in HRSG. As you said steam bypassed at the startup of the unit, and before temp matching.

I'm not sure Its about 50/60MW, at that state just GT which spin the generator. and after temp matching done we start admitting steam on ST. IV and CV get fully opened, ACV (for BP) after chimical knowledge get opened between 40-60% at Base load, Sx.TNR Signal get 100% (fixed). another notions are LDR/LDR_CMD/LDR_R (rate) get respectively 104%, 104%, 10%. Where Gx.TNR fluctuate beetween 100/102,4%...... till base load.

As you said and after temp matching when you need more load I remarked that GAS flow-rate and the steam flow-rate/temp all get increased simultaneously. and vice versa decrease load the (combined cycle) decreases the fuel flow-rate on GT and steam flow rate/temp on ST again simultaneously. Obviously its linearly according to the trends (something like speed droop), in the soft I'm still looking for that!!!!.

Note: GT from belfort France, ST from USA.

#### CSA

Chemsouhd,

Without being able to see the GE Belfort GE application code, I won't be making any further comment. As I've already said, GE Belfort code is usually by design unnecessarily and needlessly complicated, and while it may work well understanding it can be mind-bending. Trying to explain it to someone else so they can understand it can be vitually impossible. Best to get someone from GE Belfort to try to explain what their intent was (other than, "Our way is better, and complicated is best!"), and how they tried to accomplish it.

Best of luck. I don't even know if there's a French word for "Droop speed control" (since it wasn't invented in France). I've heard it might be something like "statism" but that's just a scientific wild-arsed guess (also known as a "SWAG").

#### Crasucks

Isn't it obvious? It does so because it is commanded to do so, you said so yourself. All good generators do as commanded, don't they?

Seriously, though, and in as few words as possible, when an operator clicks on Raise Spd/Ld or increases the Pre-Selected Load Control setpoint when the unit is being operated in Pre-Selected Load Control mode the fuel flow-rate into the turbine is increased, which increases the torque being produced by the turbine, which the generator converts to amps, which results in an increase in load.

For the exact details of what's happening, read on.

If one wants to make something spin, one needs to supply some force to it. That force is usually referred to as torque. The more torque applied to something, the faster it will usually spin. Decrease the torque applied to something, and it will usually slow down.

A gas turbine is a device that produces torque, and the amount of torque being produced can be varied, and is in direct proportion (usually) to the amount of fuel being burned in the combustor(s) of the gas turbine. Increase the fuel flow-rate, and the amount of torque being produced by the turbine will increase. Decrease the fuel flow-rate, and the amount of torque being produced by the turbine will decrease.
I am trying to model a load sharing simulation (code simulation) between multiple gensets on a common load bus. Are you aware of any articles/papers that would help with this task? The controls would be the simulated Vreg/Gov bias on the gensets leading to simulating the voltage and current output waveforms of the individual gensets connected to the common bus with bus frequency/voltage changes from load changes along with load sharing balances across the connected gensets. Any help would be very appreciated.

#### CSA

Crasucks,

Use your preferred World Wide Web search engine, and you will probably find what you are looking for in papers written by Masters' and Ph.D students (thesis papers).

Woodward Governor Company has a lot of "white papers" (theory and principle) they publish about load sharing and synchronization and such. (I caution you that they have a unique way of explaining Droop Speed Control; it's kind of opposite of many texts and reference books--but it's still a decent explanation.)

Best of luck!

#### PungentReindeerKing

I am trying to model a load sharing simulation (code simulation) between multiple gensets on a common load bus. Are you aware of any articles/papers that would help with this task? The controls would be the simulated Vreg/Gov bias on the gensets leading to simulating the voltage and current output waveforms of the individual gensets connected to the common bus with bus frequency/voltage changes from load changes along with load sharing balances across the connected gensets. Any help would be very appreciated.
How are you coding the simulation? The most appropriate approach (and advice related to it) will depend on how you’re trying to model load flow. Using something like Matlab or (shudder) Python to solve the differential equations is incredibly laborious if you want your models close to reality. There are a number of load flow analysis programs that are almost intuitive that have all of the heavy coding built in—you just need to input the (hopefully) OEM-provided device models for the turbine, governor, exciter, xfmrs, and set up the steady state initial conditions (line impedance, x/r ratios, etc etc).

CSA

#### Crasucks

How are you coding the simulation? The most appropriate approach (and advice related to it) will depend on how you’re trying to model load flow. Using something like Matlab or (shudder) Python to solve the differential equations is incredibly laborious if you want your models close to reality. There are a number of load flow analysis programs that are almost intuitive that have all of the heavy coding built in—you just need to input the (hopefully) OEM-provided device models for the turbine, governor, exciter, xfmrs, and set up the steady state initial conditions (line impedance, x/r ratios, etc etc).
Thank you all very much for your responses. I am coding it in C/C++. The simulation doesn't need to be perfect, it will be used as a training aid for tuning and simulating situations on paralleled diesel/gas gensets. Therefore, approximations in dynamic response are ok as long as the core dynamics of power push pull sharing between gens is simulated along with the bus voltage/frequency variations when generator power exceeds the load. The first round will hopefully be up to 16 generators supporting different sizes and configurable genset dynamics. A grossly oversimplified simulation would likely work well.