1

EGR 325

April 24, 2018

Many slides from Tom Overbye, ECEN460 #23, TAMU

§Review essential reliability services

§Frequency control§ Isochronous control

§ Droop control

§Power system examples and homework

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§ Review the NERC essential reliability services§ Frequency control

§ Ramping

§ Voltage control

§ Why are they important? What happens if they are not provided?

§ Describe the relevant dynamic behavior associated with each service

§ How are they provided?

§ Normal state, all system variables are within the normal range

§ Alert state, security level falls below a certain limit of adequacy because of a disturbance

§ Emergency state, severe disturbance fault clearing, generation tripping, load curtailment

§ In extremis, cascading outages load shedding and controlled system separation

§ Restorative state, control action is being taken to reconnect all the facilities and to restore system load.

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§ Real power and frequency dynamics are coupled

§ Frequency will change with a change in net power on the system§ Load increase or decrease

§ Power output increase or decrease

§ How is the system brought back into balance?§ Load response à new, emerging behavior

§ Generator response à Traditional method

§ Single generator

§ Multiple generator uncoordinated response

§ Multiple generator coordinated response

§ To prevent extended system operation at low frequencies, load shedding is performed to bring a system back into energy balance

§ For example, a system could follow:§ 10% load shed when frequency drops to 59.2 Hz

§ An additional 15% of load is shed if frequency drops to 58.8 Hz

§ An additional 20% of load is shed if frequency drops to 58.0 Hz

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§Control of voltage levels is carried out by controlling the production, absorption, and flow of reactive power

§Generating units provide the basic means of voltage control (synchronous generators)§ They can generate or absorb Q depending on

excitation

§ Automatic voltage regulator continuously adjusts excitation to control armature voltage

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§ The higher frequency rises (returns) at level B, the better it is for system recovery.

§ Systems with significant inertia have greater frequency restoring capability

§ The Eastern Interconnect has better recovery capabilities than ERCOT

§ As traditional steam turbines are replaced by variable generation, system inertia decreases

§ Isochronous means constant speed§ The goal of isochronous control is to maintain 60 Hz exactly.

§ Droop means that as more load that is placed on an engine, it will run more slowly.

§ As a percentage, droop is:

! = Δ$/$Δ&/&

§ Droop is defined as the % deviation in frequency that will result in a 100% change in output... A 5% droop means that a 5% change in frequency will cause a 100% change in power output

§ Governors implement the droop behavior of a generator

§ In power systems, droopi is set so that interconnected generators share in frequency recovery proportionally.

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§ Ideally we want to maintain constant system frequency as the

load changes.

§ If there is a single generator, then an isochronous governor is

used

§ The controller integrates frequency error to bring the frequency back

to the desired value

§ This cannot be used with interconnected systems because of "hunting"

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Image source: Wood/Wollenberg, 2nd editionImage source: Prabha Kundur

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7

§ Generator 3 partially fails, drops 85 MW in output§ Generator 1 is modeled as an isochronous generator

12Speed_Gen Bus 2 #1gfedcb Speed_Gen Bus 3 #1gfedcb Speed_Gen Bus1 #1gfedcb

Time (Seconds)20191817161514131211109876543210

Spe

ed (H

z)

60

59.95

59.9

59.85

59.8

59.75

59.7

59.65

59.6

59.55

59.5

59.45

59.4

§ Change in generator output is shown below

§ Generator 1 contributes most of the recovery for this *small* system

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Time (Seconds)20181614121086420

Mec

hani

cal P

ower

(MW

)

170

160

150

140

130

120

110

100

90

80

70

60

50

40

30

20

10

0

MW Mech_Gen Bus 2 #1gfedcb MW Mech_Gen Bus 3 #1gfedcb MW Mech_Gen Bus1 #1gfedcb

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§ NL = no load§ FL = full load§ 0 = nominal or rated

Image source: Prabha Kundur

Image source: Prabha Kundur

Δ"# = "#% − "# = 'Δ()# Δ"* = "*% − "* = 'Δ(

)*

Δ"#Δ"*

= )#)*

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§ “Droop Control” allows power sharing between generators

§ The desired set point frequency is dependent upon the generator’s output

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1m refp p f

RD = D - D

• R is the droop, orregulation constant• A typical value is 4 or

5%.

• At 60 Hz and a 5% droop, each 0.1 Hz change would change the output by • 0.1/(60*0.05) =

3.33%

Image source: Prabha Kundur

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§ Load independent of frequency§ Resistive loads such as heating and lighting

§ Frequency dependent load§ Fans and pumps

§ Electrical frequency à motor speed à power consumption

§ Composite load frequency dependence

Δ"# = Δ"% + 'Δ()where

Δ"% = *+* ,-./0.*12 − 4.*45657. 8+9: 1ℎ9*<.' = 8+9: − :9=>5*< 1+*469*6

'Δ() = ,-./0.*12 − 4.*4657. 8+9: 1ℎ9*<.

source: Prabha Kundur

§Load Damping Constant, D§ Is defined as a percent change in load for a 1%

change in frequency

§ D is typically 1% to 2%

§ So if D = 2%, then for the composite load on the system, a 1% change in frequency would result in a 2% change in system load

source: Prabha Kundur

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§Note Req !!

§Generators are being operated in parallel

source: Prabha Kundur

§ Using the previous 3 bus example, let generators 1 and 2 have ratings of 500 and 250 MVA respectively and governors with a 5% droop.

§ What is the final frequency (assuming no change in load)?

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To solve the problem in per unit, all values need to be on a common base (say 100 MVA)Δpm1 +Δpm2 = 85 /100 = 0.85

R1,100MVA = R1100500

= 0.01, R2,100MVA = R2100250

= 0.02

Δpm1 +Δpm2 = −1

R1,100MVA

+1

R2,100MVA

⎛

⎝⎜⎜

⎞

⎠⎟⎟Δf = 0.85

Δf = −.85 /150 = 0.00567 = −0.34 Hz→ 59.66 Hz

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§ The graphs below compare the mechanical power and

generator speed

§ Note the steady-state values match the calculated

59.66 Hz value

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Mech Input_Gen Bus 2 #1gfedcb Mech Input_Gen Bus 3 #1gfedcbMech Input_Gen Bus1 #1gfedcb

Time (Seconds)20191817161514131211109876543210

Mec

hani

cal P

ower

(MW

)

1901801701601501401301201101009080706050403020100

Time (Seconds)20181614121086420

Spe

ed (H

z)

6059.9559.9

59.8559.8

59.7559.7

59.65

59.659.5559.5

59.4559.4

59.3559.3

59.2559.2

59.1559.1

59.05

Frequency_Bus Bus1gfedcb Frequency_Bus Bus 2gfedcb Frequency_Bus Bus 3gfedcb

§ Changing to the droop to 0.01 results in less steady-state frequency error, but at the cost of a faster generator response

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Time (Seconds)20181614121086420

Spe

ed (H

z)

6059.9859.9659.9459.9259.9

59.8859.8659.8459.8259.8

59.7859.7659.7459.7259.7

59.6859.6659.6459.62

Frequency_Bus Bus1gfedcb Frequency_Bus Bus 2gfedcb Frequency_Bus Bus 3gfedcb

Time (Seconds)20181614121086420

Mec

hani

cal P

ower

(MW

)

1901801701601501401301201101009080706050403020100

MW Mech_Gen Bus 2 #1gfedcb MW Mech_Gen Bus 3 #1gfedcb MW Mech_Gen Bus1 #1gfedcb

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(W.W.S. CHAPTER 10)§ Suppose that you are given a single area with three

generating units as shown below.

Unit Rating (MVA) R (Speed Droop) (per unit on unit base)

1 100 0.01 2 500 0.015 3 500 0.015

§ The units are initially loaded as follows:

§ P1 = 80 MW

§ P2 = 300 MW

§ P3 = 400 MW

a) Assume D = 0; what is the new generation on each unit for a 50 MW load increase?

b) Repeat with D = 1.0 pu (i.e., 1.0 pu on load base). Be careful to convert all quantities to a common base when solving.

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§ Generator and system frequency control

§ Isochronous control – single generator system

§ Droop control – multi-generator systems

§ Examples for real power and frequency interdependency