3 Fulfillment of Grid Code

8/13/2019 3 Fulfillment of Grid Code

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Fulfillment of Grid Code Requirements in

the area served by UCTE by Combined

Cycle Power Plants

Dieter Diegel,Steffen Eckstein

Ulrich Leuchs,Oldrich Zaviska

Siemens AG, Power Generation , Germany

Abstract:

The continental European power system is the result of synchronous interconnection of the

electricity networks of the separate transmission system operators (TSOs) involved. To

ensure smooth operation of the system and to enable grid disturbances to be controlled, a

number of technical rules and recommendations need to be followed in operation of this

system.

The rules and recommendations of the Union for the Coordination of Transmission of

Electricity (UCTE) form a common basis for this, providing minimum requirements to be

met for grid operation on this system which is operated in overall synchronism These rules

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profitability for the system. For the TSOs to be able to meet their responsibilities,

transmission system users must comply with the technical minimum requirements and rulesspecified in the relevant Grid Codes.

The paper discusses the requirements of national Grid Codes for primary and secondary

control and the extent to which they can be fulfilled by combined cycle power plants

(CCPPs).

Examples are given of the restrictions that apply for modern gas turbines, and of the way in

which Grid Code or customer requirements can be met for combined cycle plants.

1. Introduction

In the past year, the UCTE and regional TSO associations responsible for national Grid Codes

have had very good reason to focus on compliance with and fulfillment of the requirements

that they have set forth.

There were the blackout events in Italy, Denmark/southern Sweden and the USA/Canada,

which resulted in major economic losses.

Even the variability of the causes involved illustrates that the complexity of a reliable energy

supply system presents ever greater challenges and requires more and more a coordinated

approach.

Not least of all, grid operators are being challenged to make ever larger power reserves

available, to achieve improved distribution of these power reserves within the interconnected

power system and to develop new and better load shedding concepts for response to

disturbances.

There are various reasons for the size and uniformity of the power reserves. On the one hand,

it is necessary for conventional power plants to provide control reserves corresponding to the

entire output supplied by energy producers which operate without any frequency-control

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power system, which was originally envisioned primarily as a source of mutual assistance and

optimization, is more and more becoming a commercial marketplace.Not least of all, the expanded physical size of the interconnected power system and the

variability with which the interconnections mesh are also new challenges. Due to limited

transmission capacity, reliable provision of control power within the interconnected power

system requires uniform distribution of this control power over the generating units involved.

In the future, transmission system operators must pay even closer attention to compliance

with requirements when the generating units are connected and must also use test programs to

verify the necessary flexibility of these units for grid operation.

Power plant manufacturers are working intensively in close co-operation with companies that

operate the generating units to comply with these ever more intricate rules.

These companies have a vested interest in ensuring a reliable energy supply even in the event

of grid disturbances, especially if they are responsible for supplying power to large urban

areas with many industrial plants.

Back in the 1980s, the Power Generation Group of Siemens AG was already gaining vast

experience with special grid requirements, in particular relating to steam power plants.

As gas turbines have gone on-line in single or combined cycle (Siemens GUD) power plants,

which represent a growing market share, Siemens has been gaining worldwide experience

with these machines since the ending of the 1980s.

This experience also aids us in meeting the newly defined requirements for these types of

power plants.

2. Common Grid Requirements for Active Power control of CCPPs

Frequency Stability

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If the power generation is greater than power demand, generators connected to the grid system

speed up.If the power generation is less than power demand, generators connected to the grid system

slow down. When power generation and power demand are back in balance, the frequency

stabilizes.

For correct operation of the transmission system it is necessary to hold the frequency within

defined narrow limits. Minor deviations from the frequency reference value (50/60Hz) or

absence of any such deviations show that there is a balance of generation and power demand.

Faults in the system resulting from loss of power plants, shutdown of loads, short circuits, etc.

result in deviations and gradients of varying magnitudes. These faults can result in instability

of the grid or even in grid outage. It is possible to distinguish:

- Faults within the anticipated range, controlled by provision of reserve power.

Those faults result in frequency fluctuations that remain within a control band defined by

the grid operator e.g. at UCTE = +/-200 mHz.

It must be possible to ride out loss of the largest generator in the system without frequency

moving outside the control band. This operation will be described in the subsection

Frequency Control.

- Serious system faults that are counteracted by disconnection from the interconnected

system and measures such as load shedding.

Fast decreases in frequency in the case of serious system faults can not be counteractedsolely by measures on the generating side. Protection devices are implemented which

switch off loads (load shedding) in case of a specific underfrequency.

In the case of fast decreases in frequency where the frequency remains above a

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Primary control is the automatic, stabilizing action of active power controls for the turbine-

generators interconnected in the synchronous three-phase grid. This type of control acts in the

time frame of seconds using turbine speed control.

Secondary controltakes effect after about 30 seconds and acts in the time frame of minutes.

The local Grid Codes in each country generally specify minimum requirements.

Purchaser-specific requirements that go beyond the respective Grid Codes are, however, often

specified in order to achieve competitive advantages on deregulated power trading markets.

Specifications :

For example: England/ Wales: NGC Grid Code, Connection Conditions, Appendix 3

(minimum requirements):

Plant Operating Ranges:

If there is a contractual agreement with the TSO, frequency control takes place above a

minimum generation MG of 65% registered capacity. In case of grid disturbances with

increasing frequency the control must be able to reduce the generation dynamically down

to a designed minimum operating level DMLO of 55%.

For example: Spain : RED ELCTRICA DE ESPAA, P.O.7.1.

Frequency control band !P = +/- 1.5 % of registered capacity

The required frequency dependent load change is to be demonstrated 10 seconds after the

start of a frequency simulation ramp of +/- 0.2 Hz per 30 seconds.

(It should be noted that these requirements apply to the overall power plant. In combined-

cycle plants, the ST does not participate in frequency regulation, so the GT has to provide

1.5 times the response).

Operating frequency demanded by the grid system

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The regulator must guarantee stable operation of the unit for an indefinite time, for any

frequency between 47.5 Hz and 51.5 Hz and any load between the load of the auxiliary

service and the maximum power that can be generated by the unit .

Allowable power dip on rising/falling system frequency

Requirement:

Many Grid Codes contain a requirement to avoid excessive active power dips on fallingsystem frequency. Gas turbines, in particular, tend to respond to frequency reductions with

pronounced output changes that depend on the ambient temperature.

Specifications:

For example: Greece : RAE, CC7.3.1.1.1.

operate continuously at normal rated output at transmission system frequencies in the range

49.5 Hz to 50.5 Hz

Load rejection / island operation

Requirement :

In many Grid Codes the requirements above are compulsory.

Load rejection

Various electrical causes such as frequency under a minimum limit, stability problems and too

low grid voltage can cause the circuit breaker to open and disconnect the power plant from the

grid during operation. After opening of the circuit breaker house load is still supplied (about 5

to 10 MW). This is called load rejection to house load. If opening of the generator breaker

takes place in response to a system fault there is then a load rejection to 0 MW

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A blanket requirement for stable operation of a single generator in all possible island

configurations cannot be met. If there is a requirement for the generating unit to continue in

stable operation, a purchaser-specific automation concept must be drawn up. For this purpose

detailed information and technical data on the purchaser's requirements and the possible

configurations of the island system are necessary.

Specifications :

German Transmission Code 2003

1. Load rejection on house load

The generating unit must be designed to control the load rejection to house load .

from each permissible operating point.

2. (Grid) island operation capability

Each generating unit must be capable of controlling the frequency under the condition

that the respective generation shortage is not more than the primary operating reserve.

In case of generating surplus the generating unit must be able to reduce output down

to minimum generation.

Control of a short circuit close to the power plant

Requirement :

The short circuit clearance protection will control failures in the system in a time frame of

approximately 100 ms. If this is unsuccessful, a back-up protection feature then acts in a time

frame of 100 to 250ms to maintain stable and undisturbed load operation. The requirement to

overcome a short circuit in the system applies both to the generator voltage control and to the

turbine frequency/load control.

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Even though the UCTE has developed a number of technical and organizational rules printed

in the UCTE Operation Handbook, the responsibility of the national TSOs must still bedetermined in their own guidelines.

Because grid structures vary in different countries (e.g., in the distribution of generating units

over the area of the country) and due to the way in which the interfaces to the other

transmission systems are defined and thus to the way in which energy is exchanged with these

other systems over the interconnected power lines, it is necessary to define specificrequirements.

Non-UCTE nations (such as Ireland) are second to none in terms of the requirements placed

Fig. 1 : UCTE members

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4. Control Strategy of SIEMENS Combined Cycle Power Plants

The range within which a GUDpower plant can contribute to grid frequency regulation is a

function of the power plant operating mode and the associated overall conditions. Interaction

between the operating modes of all of the relevant components, such as the gas turbine, heat-

recovery steam generator and steam turbine, must be taken into account, especially where

dynamic processes are involved.

In the GUDprocess, Siemens gas turbines should operate within the largest possible load

range with nearly constant turbine outlet temperatures, with NOX requirements taken into

account here. The turbine outlet temperature controller regulates the compressor air mass flow

to a specified fuel/air ratio. In other words, the air mass flow rate through the compressor

must be adjusted according to the flow of fuel entering through the control valves. An

adjustable row of inlet guide vanes, driven by an actuator, is located at the compressor inlet.

OTC temp. IGV position

1

0.5

11

0 5

1

HP steam press.HP valve opening

Valve

Temp.IGV

Speed-/Admiss.controller

ST controller

GT controller

Speed/Load &OTC temp. lim.controller

OTC temp.(IGV)controller

Gas turbineHRSG Steam turbine

Generator

IGV

G

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In order to hold back a required control reserve, a GUDpower plant must operate in the

part-load range. The gas turbine is then operated under load-controlled with a subordinate

speed controller. The unit is controlled based on a specified unit load setpoint. As soon as the

grid frequency goes outside of a set insensitivity band, the frequency influence then acts on

the unit power setpoint, changing this and the speed controller corrects the lift setpoint (for

the fuel valves and inlet guide vanes). Unit output is regulated to correspond to the new

requirement. In the event of overfrequency the load is reduced and in the event of

underfrequency the load is increased.

With these dynamic processes, the speed/load controller of the gas turbine provides for an

optimum and stable combustion process.

5. The Excellence of SIEMENS CCPPs in Frequency Response

Now that an explanation has been provided as to the general conditions and the requirements

of the transmission system operators on the one hand and the Siemens power plant control

strategy on the other hand, the results of a number of tests will be used to illustrate how

Siemens GUDpower plants respond to particular events during grid operation.

The following points will be explored on the basis of tests:

Primary control in the event of underfrequency

Primary control in the event of overfrequency

Load rejection by a gas turbine from base load to house load

Load rejection by a gas turbine to islanding mode

Fig. 3 : GT Control, Speed(Frequency)/ Load Controller Principle

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Primary control in the event of overfrequency

In response to overfrequency simulated by a ramp function of +0.2 Hz within 10 seconds, the

GUD reduces the power output.

Load rejection by a gas turbine from base load to house load

Riding out a load rejection from base load to house load using a gas turbine entails holding

speed below the overspeed trip limit without throttling the fuel valves so far that flameout

occurs.

Fig. 5 : Primary Frequency Response on Overfrequency

-14

-12

-10

-8

-6

-4

-2

0

-5 0 5 10 15 20 25 30 35

0

0,05

0,1

0,15

0,2

0,25

Measured power response

UCTE / Spain requirement

Greece requirement

England requirement

Frequency injection

Frequency deviation [Hz]

Time [s]

Power response [% on RC]

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Fig. 6 shows load rejection to house load initiated by opening the circuit breaker at a plant

located in Italy.

Load rejection by a gas turbine to islanding mode

Load rejection to islanding mode is gaining in significance. This is a trend that has become

more apparent since the blackout events of last year. Fig. 17 shows load and frequency curves

for plant in Germany during load rejection from part load to islanding mode.

6. Participation of ST in Primary Control

It was primarily contractual agreements that led to the realization that only by involving the

steam turbine could the power output requirements be met.

Fig. 7 : Load Rejection to Island

20

40

60

80

100

120

140

160

-1,00 0,00 1,00 2,00 3,00 4,00 5,00 6,00 7,00 8,00

Time [s]

49,9

50

50,1

50,2

50,3

50,4

50,5

50,6

GT power

GT frequency

Frequency [Hz]Power [MW]

opening of circuit breaker for island operation

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The block diagram of the new control module is shown in Fig. 9. The charging of thermal

storage is initiated by switching from natural variable-pressure mode to modified variable-

pressure mode. This changes the setpoints in the unit control module such that the turbine

inlet valves begin to throttle accordingly. At the end of the throttling process the storage has

been charged and the steam section is operating in modified variable-pressure mode, ready for

the steam turbine to participate in primary control.

The grid frequency is compared to a frequency setpoint, with the frequency deviation (f)

used to generate a frequency-dependent setpoint component (SETP) and perform a dynamic

analysis (SETP_DYN). The SETP_DYNparameter is used to generate control signals in the

unit coordination control system, with static weighting applied for the steam turbine control

system. The statically weighted signals are used to correct the steam turbine setpoints and the

control deviations, causing the desired release of reserve capacity within seconds via the

control valves.

500

470

460

450

PUNIT(MW)

PUNIT

PGT(MW)

PGT

PST

PGT = P UNIT

operation with active STbase load 450 MW

50

40

30

20

10

0

50

40

30

20

10

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reserve capacity. Once the reserve capacity has been made available, the steam section is

automatically returned to modified variable-pressure mode.

Shifting part of the primary control power to the steam turbine provides two important

advantages over the concept used previously:

The desired level of primary control power can be held ready at higher base load (by reducing

the gas turbine contribution by the magnitude of the steam turbine contribution).

Simultaneously, the dynamic characteristics of the unit are improved through temporary

activation of the steam process (increases in steam turbine output can be implemented at the

fast positioning speed that is a feature of the turbine inlet valves).

A comparison of the two concepts for releasing reserve capacity is shown in Fig. 10.

At present, a control concept is being developed for primary control using the ST in the range

of small frequency deviations (up to about 50 mHz). The gas turbine in this case is called

upon for large frequency dips and for secondary control. This concept will mobilize the

advantages to be gained by shifting a part of the primary control reserve to the steam turbine.

Controlled access to the ST control power contribution in the range of small frequency

deviations substantially improves the dynamic characteristics of the unit and ensures a gas

turbine operating mode that minimizes life-limiting effects.

7. Conclusion

Over its many years of experience in the power plant business, the Siemens Power Generation

Group has kept pace with the new demands for involving the generating units in frequency

control within the interconnected power system.

A steady stream of new and innovative approaches to existing and proven control concepts

helps us meet the requirements of the transmission system operators. The complexity of a

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8. References

Activating the steam side increases base load capacity. Modern Power Systems,

January 2002

Advanced primary control with combine cycle power plants. Proceeding of the 3rd

International Conference Electric Power Quality and Supply Reliability, Sept. 4-6,

2002, Haapsalu, Estonia

Einsatz der Dampfturbine eines GUD-Kraftwerkes zur Primrregelung. EPE

Electric Power Engineering 2003, 5thInternational Scientific Conference, Jan 28-29,

2003, Visalaje, Czech Republic

ESB Grid Code / requirement, Ireland

Frequency Response Capability of Combined-Cycle Power Plants 12th Conference

of the Electric Power Supply Industry Cepsi 02-06 November 1998

GRTN, TRANSMISSION AND DISPATCHING CODE / requirement, Italy

NGT Grid Code / requirement, England/Wales

RAE Grid Code / requirement, Greece

RED ELCTRICA DE ESPAA Grid Code / requirement, Spain

Siemens Power Journal 2/2000

Siemens Power Journal online May 2002

Transmission Code 2003 / requirement, Germany

UCTE Operation Handbook, www.ucte.org

UNE Grid Code / requirement, Morocco

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Appendix 1, Requirements of various TSOs

UCTE Members RC= registered capacity

Country / Grid Code Primary Control

Controlband/Deadband/Dynamics

Secondary Control

Controlband / Dynamics

Additionals

UCTE OpHB

Policy 1

Load frequency

control(final draft 1.9E,

31.12.2003)

based on

UCPTE*-Ground

Rules

of 01.06.98

Primary control bandaccording to the control zone.

Deadband < 10 mHz Dynamics: primary operating

reserve / 30 s linear according

to control zone.

At !f = -0.2 Hz provision offull primary operating reserve

Value of 8%/min for oil / gaspower plants will be used as

an aid and are not required. The tracking-speed can be

set from 50 to 200 s.

Germany

Transmission

Code 2003

Primary control band +/-2%of RC

Fully available at !f = 200mHz after 30 s for 15 min.

Gradient 2% / 3 0s Deadband < +/-10 mHz

Not a must

Right to participate insecondary frequency control

after compliance with

prequalification

Load rejection to house load supply must be controlled. Primary reserve additional to speed of load change and

secondary reserve

Grid Island Mode:control band: increase !P = +1.5%

load decrease until minimum load reached

details must be discussed between

grid and plant operators Load dip due to falling frequency restricted according

to Figures 2.1 und 2.2

p

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Country / Grid Code Primary Control

Controlband/Deadband/Dynamics

Secondary Control

Controlband / Dynamics

Additionals

Spain

RED Grid Code Primary control band +/-1.5%

of RC

Fully available at !f = 200mHz after 30s for 15 min.

Deadband < +/-10 mHz Droop must be adjustable

Not a must:

A condition for participationin secondary control by

generators is a respective

Qualification of OS

Italy

GRTN GridCode

CA, CC und

11

StandardCEI 11-32

Primary control band +/-3% oRC

Fully available at !f = 200mHz after 30s for 15 min.

Deadband < +/-10 mHz Droop 2 8%, must be

adjustable

Specific agreement

SC-band = +/-6% of theactive plant power with 8%

/min of the GT part of the

combined cycle

The primary and secondary control windows areindependent from each other. The overall control

window is the sum value of the two.

Islanded Mode: correct operation in an islanded grid.... restore the frequency on the island at rated value of

+/-0.25%..

Greece

RAE

Grid Code

Primary control band +/-3%of RC in the load range of 50

97% RC, then linear

decrease.

Fully available at !f = 200

mHz after 30 s for 15 min. Deadband < +/-10 mHz Droop must be adjustable

according to the requirements

of HTSO

Secondary operating reservenot less than 3% of RC in a

load range of 50 97% RC,

then linear decrease

Remain synchronized with the grid at frequency 47.5 to49.5 Hz and 51.5 to 52.5 Hz for a duration of 60

minutes

Remain synchronized with the grid at frequency 52.5 to53 Hz for a duration of 5 s.

Minimum load not greater than 35% RC Load dip due to falling frequency:

Supply of rated load in the frequency range of 49.5

50.5 Hz.

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Non UCTE Members,

Country / Grid Code Primary ControlControlband/Deadband/Dynamics

Secundary ControlControlband / Dynamics

Additionals

Morocco UNE

Techn. rules for

the operation of the

connection grid

Spain Morocco

Primary control band +/-2.5%of RC (expotential Ta = 10s)

at !f = 200 mHz

Deadband < +/-10 mHz Droop 2 6%

The COMELEC operatingzone must be equipped with a

grid operation system.

Morocco is a COMELEC-member. COMELEC isbeing represented within UCTE by REE (Spain). For

COMELEC the technical rules of UCTE are valid.

England / Wales

NGT Grid Code Min. requirement +/-10% RC

10s after start of frequency

ramp of -0.5Hz / 10 s the

frequency response must be

10% RC.

Deadband < +/-15 mHz. Limited frequency control in

case of f > 50.4Hz

Droop 3 5% NGT normallyrequires 4%.

Min. requirement +/-10% RC30 s after start of frequency

ramp of 0.5Hz / 10 s the

frequency response must be

10% RC.

No load decrease on frequency fall of up to 49 Hz. Target frequency correction with +/-100 mHz must be

possible.

Islanded ModeThere must be the ability to control an island formation

between 55% and 100% RC.

Load dip due to falling frequency:In the range 50.5 to 49.5 Hz continuous active power !

In the range 49.5 to 47 Hz linear decrease in active

power by not more than 5%.

Ireland

ESB Grid Code

Primary operation reserve +/-

5% RC in the load range 50 95% RC, then linear decrease

allowed

Fully available in real time atfrequency nadir between 5

15 s

Secondary operating reserve

not less than 5% of RC in theload range 50 95% RC,

with linear decrease then

allowed.

Fully available in the timerange of 15 90 s

Remain synchronized with the grid at frequency 47.5 to

52.5 Hz for a duration of 60 min Remain synchronized with the grid at frequency 47.5 -

47 Hz for a duration of 20s.

No load increase in the range of 49.5 50.5 Hz Minimum load not < 50% RC for CC and not < 35%

RC for steam turbine plant.

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3 Fulfillment of Grid Code