fulfillment of grid code requirements in the area … · the technical rules and recommendations...

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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

and recommendations leverage the exchange of electric power beyond the boundaries of the

separate countries that form this synchronously interconnected system, and also promote non-

discriminatory exchange of data for this task.

The technical rules and recommendations do, however, give the individual TSOs the option of

going beyond mere compliance with these minimum requirements, implementing more

stringent requirements or even defining these in greater detail. As a result, individual TSOs

or regional TSO associations have drawn up national Grid Codes with a number of functions

such as defining the sharing of responsibilities for security of supply, reliability and

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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 rules

specified 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

capability, such as renewable energy plants like wind power stations. These control reserves

serve to compensate for power fluctuations or outages at wind power stations.

On the other hand, liberalization of the electric power markets in Europe and heavy emphasis

on unhindered commercial trading of electric power across national boundaries wherever

possible have also presented new challenges to the transmission systems. Great Britain led the

way with its revision of grid requirements. Shortly thereafter, members of the UCTE followed

suit and reviewed their national Grid Codes for the European mainland. The interconnected

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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

Requirement :

For grid system operation, it is required that the power generated is continuously matched to

demand for the power plant. One yardstick for this balance is the system frequency. If power

generation and power demand in the grid system are the same under undisturbed generation

conditions, the system frequency is exactly equal to the rated frequency (50/60 Hz).

Unforeseen events such as perturbations in the grid system or shutdown of power plants

create an imbalance between generation and demand, and are reflected in changes in the

system frequency.

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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 counteracted

solely 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

disconnection limit, it is the task of the generators to remain in a stable load operation

mode.

� Frequency control

Requirement:

The reaction on frequency deviation caused by an event in the grid is handled by the

frequency control. This is implemented in two time ranges.

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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 control takes 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 ELÉCTRICA DE ESPAÑA, 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

Requirement :

Bidding and order specifications and Grid Codes frequently call for power operation in

frequency ranges between 95 and 103 %. In some cases there is a requirement for short-term

ability to withstand overfrequency above 103 %, say for 20 seconds without grid

disconnection.

Specifications :

For example: Italy : GRTN, TRANSMISSION AND DISPATCHING CODE, 5.10.

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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 falling

system 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.

Island operation

The expression “island” here refers to the formation of a partial grid after a system fault with

disconnection from the interconnected system, with one or more generators then supplying

the remaining loads. At the moment of disconnection from the interconnected system the

terminal load of the generators must suddenly adapt to the new load level. The transient and

the remaining generation must be managed by the frequency/load controller.

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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.

3. Overview of Requirements of European National Grids

As a part of the ETSO (European Transmission System Operators), the "Union for the Co-

ordination of Transmission of Electricity" (UCTE) is the association of transmission system

operators in continental Europe which interconnects and supplies the vast majority of the

population of Europe with electrical power.

E

i

d

B

o

t

o

r

N

o

o

T

v

o

T

e

Fig. 1 : UCTE members

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

n the “UCTE Operation Handbook,” the responsibility of the national TSOs must still be

etermined in their own guidelines.

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

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

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

ther systems over the interconnected power lines, it is necessary to define specific

equirements.

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

n energy producers. In fact, even stricter regulations than those of the UCTE countries are

ften necessary due to the small size of their grids.

he overview appended to this paper explains some of the important parameters present in

arious national Grid Codes. Due to the number and variability of the requirements, it was

nly possible to compare a number of selected points.

he table shows the droop, the conditions for primary and secondary control, information on

ffective load generation and requirements for islanding mode.

4. Control Strategy of SIEMENS Combined Cycle Power Plants

The range within which a GUD power 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 GUD process, 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.

T

t

v

OTC temp.

Load

IGV position

1

0.5

0.5 1

1

-Load control with speed/ load controller-OTC temperature = f(load)

-Load control with speed/ load controller -Temp. control with IGV controller

Load

1

0.5

0.5 1

1

HP steam press.HP valve opening

Valve

Sliding pressure

Temp.IGV

Speed-/Admiss.controller

ST controller

GT controller

Speed/Load &OTC temp. lim.controller

OTC temp.(IGV)controller

Gas turbine HRSG Steam turbine

Generator

IGV

G

Sliding pressure mode (steam valves are fully open)

Fig. 2 : Combined Cycle Power Plant – SIEMENS Control Principle (Single Shaft)

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he speed at which the vanes can be positioned by the actuator is an important criterion in

erms of the response time of the gas turbine. The working range of the adjustable inlet guide

anes is between approx. 55% and 100% of the GT load. Depending on the positioning time

involved, the maximum power increase can be achieved very fast. This property makes gas

turbines eminently suitable for secondary control and frequency support.

The load-change capability of the gas turbine is determined by the dynamics of the turbine

outlet temperature control system.

The rate of temperature change in thick-walled components is of critical importance for

operation of the heat-recovery steam generator (HRSG). Changes in temperature lead to

increased life expenditure and must therefore be monitored. By monitoring this parameter the

boiler is protected against overstressing. This leads us to another important point which limits

the range of the GUD power plant in terms of dynamic processes.

The steam part of the GUD power plant normally operates in variable-pressure mode. The

control valves of the steam turbine are fully open. The volume of steam generated is

determined by the power output of the gas turbine. Gas turbine output has to be raised to

increase the contribution made by the steam turbine (ST) to the power generated by the

overall power plant. ST load changes are thus determined by the dynamic response within the

minutes timescale for the HRSGs. In this operating mode, the steam turbine is not suitable for

primary control (which must take place within seconds). However, it will be able to engage in

secondary control.

In the ST operating mode described above, the gas turbine is the component called upon in

the GUD power plant for providing primary control.

Since the requirements for the entire power plant unit have been set forth in the Grid Code

agreements and in the contracts, this means that greater demands are placed on the load

change capabilities and on the flexibility of the gas turbine.

In a GUD power plant, primary and secondary control can be provided in the range of 65%

to 100% of unit output, due to the working range for the adjustable inlet guide vanes, and is

accomplished using the gas turbine controller (speed/load controller).

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Pr

P

hv

Frequency influence

Speed controller

Load controller

Response limit

Limit gradient

Synchronized

Kp

nr

n

Injection of Test Function

I

p

s

g

t

t

r

u

W

o

5

N

o

s

S

T

T

v

e
Fig. 3 : GT Control, Speed(Frequency)/ Load Controller Principl
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n order to hold back a required control reserve, a GUD power plant must operate in the

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

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

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

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

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

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

nderfrequency the load is increased.

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

ptimum and stable combustion process.

. The Excellence of SIEMENS CCPPs in Frequency Response

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

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

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

iemens GUD power plants respond to particular events during grid operation.

he 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

he tests of primary control were initiated by injection of a test function set to the actual

alue for speed (Fig. 3).

0

2

4

6

8

10

12

-5 0 5 10 15 20 25 30 35-0,25

-0,2

-0,15

-0,1

-0,05

0

Measured power response

UCTE / Germany requirement

Italy requirement

England requirement

Frequency injection

Frequency deviation [Hz]

Time [s]

Power response [% on RC]

• Primary control in the event of underfrequency

When an underfrequency is simulated, the power plant unit responds with a load increase

which, in the range shown below, is produced solely by the gas turbine.

y
Fig. 4 : Primary Frequency Response on Underfrequenc
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• Primary control in the event of overfrequency

y

-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 responseUCTE / Spain requirementGreece requirementEngland requirementFrequency injection

Frequency deviation [Hz]

Time [s]

Power response [% on RC]

Fig. 5 : Primary Frequency Response on Overfrequenc

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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. 6 :

Load Rejection

To House Load

0,0

20,0

40,0

60,0

80,0

100,0

120,0

-1,5 0,0 1,5 3,0 4,5 6,0 7,5 9,0 10,5 12,0 13,5 15,050

50,5

51

51,5

52

52,5

53

GT power

GT frequency

Power [% on RC] Frequency [Hz]

Time [s]

Opening of circuit breaker

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.

It wa

steam

Invo

in th

valv

very

and

So a

valv

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 8,00Time [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

Fig. 7 : Load Rejection to Island

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Participation of ST in Primary Control

s primarily contractual agreements that led to the realization that only by involving the

turbine could the power output requirements be met.

lvement of the steam turbine in rapid unloading processes has already been implemented

e control concepts at a number of plants. The ST is equipped with fast-acting control

es. Rapid closing of these valves (Fast Valving, Fig.8) can reduce the steam turbine load

quickly. This temporarily reduces the acceleration moment of the turbine-generator unit

effectively limits the overfrequency.

s not to disrupt the technological process, what then follows is a slow opening of the

es to a value close to the original one.

These features would allow the ST to assist in turbine interception in the event of a rapid load

reduction for load rejection from interconnected grid operation to island operation.

“A

ope

con

Fre

F

Smf

S

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ctive” participation of the steam turbine in rapid loading processes requires that the ST

rate in modified variable-pressure mode. This operating mode requires that the unit

trol concept be expanded to include additional function modules, such as the Module for

quency Response.

0

20

40

60

80

100

120

-10,00 0,00 10,00 20,00 30,00 40,00 50,00 60,00 70,00 80,00 90,00 100,00

Time [s]

0

0,25

0,5

0,75

HP valveIP valveST powerFrequency deviation

Frequency deviation [Hz]Valve position [%] / power [% on RC]

Start of frequency injection

Fig. 8 : Fast Valving

ig. 9 : New control concept

Setpoint generation for individual pressure sections

Modifiedsliding pressureON/OFF

teamass

low Detection of energy charging/release,

team pressure

Generation of control signals for power controller

∆ f∆ SETP = F (∆ f)

f_SETP

f_ACT

+-

Dynamicweighting

∆ SETP_DYN

Staticweighting

Unitcoordination

control

Steamturbinecontrol

NEW MODULE

Generation of control signals

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_DYN parameter 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.

T

co

e

500

470

460

450

440

430

PUNIT

(MW)

∆PUNIT

∆PGT

(MW)

∆PGT

∆PST

∆PGT = P∆ UNIT

operation with active STbase load 450 MW

operation with passive STbase load 436 MW

0 5 10 15 20 30t (s)

50

40

30

20

10

0

50

40

30

20

10

0

Fig. 10 : New Modul

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he required control signals are generated and used by the unit coordination control system to

ordinate intervention by the gas turbine and steam turbine control systems during release of

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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

power plant offers a wide variety of approaches for improving the operating mode in terms of

frequency control, but there are physical limits, which nevertheless must be kept in mind.

Our company sees special customer requirements (such as disconnection of an industrial

power plant from the grid with subsequent isolated operation, for example) as a challenge and

at the same time an opportunity to expand our realm of experience. That is why SIEMENS is

also acting as a consultant to transmission system operators in working out new concepts.

In the future, the need to maintain a defined power control reserve within electrical grids will

grow in importance.

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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 Primärregelung’. EPE –

Electric Power Engineering 2003, 5th International 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 ELÉCTRICA DE ESPAÑA 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

http://www.ucte.org/

http://www.ucte.org/

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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 OpHBPolicy 1‘Load frequencycontrol’(final draft 1.9E,31.12.2003)based onUCPTE*-GroundRulesof 01.06.98

� Primary control bandaccording to the control zone.

� Deadband < 10 mHz� Dynamics: primary operating

reserve / 30 s linear accordingto control zone.

� At ∆f = -0.2 Hz provision offull primary operating reserve

� Value of 8%/min for oil / gaspower plants “will be used asan aid and are not required”.

� The “tracking”-speed can beset from 50 to 200 s.

Germany

TransmissionCode 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 controlafter compliance withprequalification

� 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 reacheddetails must be discussed betweengrid and plant operators

� Load dip due to falling frequency restricted accordingto Figures 2.1 und 2.2

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Secondary Control


Additionals

SpainRED 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 bygenerators is a “respectiveQualification” of OS

Italy

GRTN GridCode“CA”, “CC” und“11”

StandardCEI 11-32

� Primary control band +/-3% ofRC

� 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 thecombined cycle

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

RAEGrid Code

� Primary control band +/-3%of RC in the load range of 50– 97% RC, then lineardecrease.

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

� Deadband < +/-10 mHz� Droop must be adjustable

according to the requirementsof HTSO

� Secondary operating reservenot less than 3% of RC in aload 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 60minutes

� 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,



Secundary Control


Additionals

Morocco UNE“Techn. rules forthe operation of theconnection gridSpain – 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 agrid operation system.

� Morocco is a COMELEC-member. COMELEC isbeing represented within UCTE by REE (Spain). ForCOMELEC the technical rules of UCTE are valid.

England / WalesNGT Grid Code

� Min. requirement +/-10% RC10s after start of frequencyramp of -0.5Hz / 10 s thefrequency response must be10% RC.

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

case of f > 50.4Hz� Droop 3 – 5% NGT normally

requires 4%.

� Min. requirement +/-10% RC30 s after start of frequencyramp of 0.5Hz / 10 s thefrequency response must be10% RC.

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

possible.� Islanded Mode

There must be the ability to control an island formationbetween 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 activepower by not more than 5%.

IrelandESB Grid Code

� Primary operation reserve +/-5% RC in the load range 50 –95% RC, then linear decreaseallowed

� Fully available in real time atfrequency nadir between 5 –15 s

� Secondary operating reservenot less than 5% of RC in theload range 50 – 95% RC,with linear decrease thenallowed.

� Fully available in the timerange of 15 – 90 s

� Remain synchronized with the grid at frequency 47.5 to52.5 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.

fulfillment of grid code requirements in the area … · the technical rules and recommendations...

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