High Frequency Deviations within the European Power System

High Frequency Deviations

26 VGB PowerTech 6/2009

High Frequency Deviations within the European Power System – Origins and Proposals for ImprovementTobias Weißbach and Ernst Welfonder

Authors

Dr.-Ing. Tobias Weißbach

Professor Dr.-Ing. Ernst Welfonder

Institute of Process Engineering and Power Plant Technology (IVD)

Department of Power Generation and Automatic Control

Universität Stuttgart, Stuttgart/Germany

Kurzfassung

Große Frequenzabweichungen im Europäischen Verbundnetz

– Ursachen und Verbesserungsvorschläge –

Da der Stromhandel europaweit nahezu aus-schließlich im 1-h-Raster erfolgt, treten zum Stundenwechsel große Leistungsungleichge-wichte zwischen dem sich überwiegend konti-nuierlich verhaltenden Lastgangverlauf und dem treppenförmigen Fahrplanverlauf auf. Die-se über die Jahre größer werdenden Leistungs-ungleichgewichte führen zu ebenfalls größer werdenden Frequenzabweichungen, die be-reits jetzt mit erheblichen Nachteilen für den Kraftwerks- und Netzbetrieb verbunden sind.Die höhere Belastung der Kraftwerksblöcke, die langfristig in die Leistungspreise der Pri-märregelung eingepreist werden muss, sowie der bei größer werdenden handelsbedingten Leistungsungleichgewichten ansteigende Be-darf an Sekundärregelarbeit führen langfristig unweigerlich zu steigenden Regelenergieko-sten. Zudem steht insbesondere während den mor-gendlichen und abendlichen großen Frequenz-abweichungen ein erheblicher Teil der vorge-haltenen Primärregelreserve nicht mehr zur Verfügung, so dass die auf die Primärregelung bezogenen Auslegungskriterien der UCTE be-züglich der Regelleistungsaktivierung nach einem Ausfall von 3000 MW nicht mehr erfült sind.Der vorgestellte Verbesserungsvorschlag sieht eine zweigestufte, sich ergänzende Maßnah-men-Umsetzung vor, indem durch Einführung eines neuen Stromproduktes die Fahrplanmel-dungen näher an die tatsächlichen rampenför-migen Lastprofile gebracht und insbesondere große Fahrplansprünge vermieden werden so-wie auf Basis der vorliegenden Fahrpläne und das zu erwartende Lastgangverhalten preis-günstigere Ausgleichsenergie seitens des ÜNB day-ahead geordert wird.Basierend auf den Ergebnissen eines zu die-sem Thema durchgeführten VGB-Forschungs-projekts und zahlreichen Gesprächen mit den Marktteilnehmern beabsichtigt der VGB, die vorgeschlagenen Maßnahmen in Abstimmung mit dem BDEW und der EURELECTRIC natio-nal und europaweit zur Diskussion zu stellen.

Introduction

With the deregulation of the electrical energy market, large unintended frequency deviations occur (within the European power system) in the course of every day, mainly at the change of the hour ( F i g u r e 1 ). Among other as-pects, the appearance of large frequency rises in the mornings and large frequency drops in the evenings is remarkable. The observed magnitudes of the frequency deviations regularly reach ∆fmax = 140 mHz and above, lasting from 10 – 15 min up to more than 30 min in several cases.

An evaluation of the frequency deviations since October 2001 shows an increase both of their occurrence and their durations in the long-run [1, 2]. Also remarkable is the in-crease of the ensemble-averaged magnitude of the frequency deviations during the winter months 2008/09, shown in F i g u r e 2 using the example of December 2008 compared to December 2007. The method of “ensemble-averaging” is briefly described under the heading “Analysis of the Origins of the Fre-quency Deviations”.

The frequency deviations bring about consid-erable disadvantages for the power plant and power system operation already today (see “Impact on Power Plant and Power System Operation”). Therefore, within the framework of a VGB research project the origins of fre-quency deviations were analysed comprehen-sively (see “Analysis of the Origins of the Fre-

quency Deviations”). The results verify that the origins of the frequency deviations are system inherent, i.e. according to current mar-ket boundaries and system rules of the dereg-ulated energy market.

Based on these results and numerous discus-sions with all market participants, proposals to improve the system behaviour have been developed (see “Measure”), which the VGB intends to put up for discussion on a national level in co-operation with the BDEW, as well as on a European level in co-operation with EURELECTRIC.

Impact on Power Plant and Power System Operation

Triggered by the occurring power imbalances and resulting frequency deviations, the pri-mary and secondary controlled power plant units are utilised to re-establish the active power balance. This leads to highly negative impacts on the power plant units themselves, especially with respect to the wear of individ-ual components and actuators [3]. Initially, primary control power is intended to balance large generation and load outages, which nor-mally do not happen more often than a few times a week.

Large frequency deviations and the subse-quent large actuations within primary control-led power plant units can actually appear more than 10 times per day, especially during the morning and evening hours (see “Analysis of the Origins of the Frequency Deviations”).

50.1

f [Hz]

50.0

49.9

04:00 a.m 12:00 p.m 08:00 00:00

Frequency behaviour 21-12-2006

Time -120 mHz

50.04

f [Hz]

50.00

49.96

49.92

49.88

49.84

Frequency drop29-11-2007

10 min

-140 mHz

Time

09:00 p.m. 09:10

Figure 1. Current operational frequency behaviour, almost similar every day.


VGB PowerTech 6/2009 27

00:00a.m

08:00

f [Hz]

p.m.

50.10

50.08

50.06

50.04

50.02

50.00

49.98

49.96

49.94

49.92

49.9002:00 04:00 06:00 10:00 12:00 02:00 08:0004:00 06:00 10:00 12:00

December 2007

December 2007December 2008

Time

Figure 2. Ensemble-averaged daily frequency curves for December 2007 and December 2008.

PL

[GW]360340320300280260240

0

Average load behaviour within the European Power System, winter months 2007

Controlarea 1

Controlarea 2

Controlarea n

0:00 4:00 8:00 12:00 04:00 08:00 00:00a.m. p.m. time

1

2

3

4

1

2

34

Deterministicpower imbalancesdue to schedulechanges

Stochastic powerimbalances due tounpredictableload deviations

Examples:power-on and -offof large consumers

change of the outside temperature

power-off ofelectrical heating

error for windpower feed-in

Figure 3. Classification of possible power imbalances within an undisturbed power system schematic representation.

340

320

300

280

260

240

220

200

50.06

50.04

50.02

50.00

49.98

49.96

49.94

360

00:00a.m

08:00Timep.m.

02:00 04:00 06:00 10:00 12:00 02:00 08:0004:00 06:00 10:00 12:00

00:00a.m

08:00Timep.m.

02:00 04:00 06:00 10:00 12:00 02:00 08:0004:00 06:00 10:00 12:00

a) Average frequency of January to March and October to December 2007 (winter months)

b) Average load of January to March and October to December 2007

6 13 GW

PL

PG, sch, 100%

Negative Positive Negative Positive Negative

f[Hz]

PL[GW]

PG, sch[GW]

Figure 4. Ensemble-averaged frequency and load curves for the winter months 2007.

The secondary controlled power plants are regularly activated as well to finally compen-sate the imbalances between power generation and consumption within the various control areas.

The resulting higher power plant stress, which has strongly increased during the last years, implies the necessity to revalue the costs for primary control reserve power activation. To-gether with the increasing amount of required secondary control energy in case of further in-creasing power imbalances, the observed trend is going to lead to higher control energy costs.

Additionally, especially during the evening hours, a large part of the primary control re-serve power is repeatedly activated, which means that the respective UCTE design hy-pothesis preliminaries for the primary control reserve activation after the sudden loss of 3000 MW generating capacity [4] cannot be ensured during these time periods. Further risks from the power system point of view, like unforeseeable active power flows on transmis-sion lines and a possible subsequent overload-ing of individual system components [2].

Analysis of the Origins of the Frequency Deviations

For the analysis of the origins of the current frequency behaviour, three aspects are deci-sive:

identification of the correlation between –the frequency and load behaviour, based on long-term measurements,

evaluation of the current practice of load- –coverage of the market participants,

simulations, starting from the boundary –conditions above.

Cor re l a t ion be tween Frequency- and Load Behav iour

Since frequency deviations represent only the summarised power imbalances within the en-tire power system, an overall consideration is required. As can be seen in F i g u r e 3 , a dis-tinction between stochastic load deviations and deterministic power generation deviations is possible1. Stochastic load deviations occur at any time at various places and with any sign. Within the whole power system, the sto-chastic power deviations in n control areas only sum up multiplied with the approximate factor 1/Ïn, whereas the deterministic power deviations accumulate linearly to high power excesses.

1 For the investigation, deterministic schedule-based load deviations like pumped storage plants in pump operation are assigned to the generation side



This noise reduction effect is also used by ensemble-averaging the measured daily fre-quency curves as well as the corresponding load curves [5] for the winter months, F i g -u r e 4 . Hereby, the influence of the stochastic load deviations is further reduced to 1/√Ndays

= 1/√182 ⩠ 7.4 %.

Opposing the average frequency and system load curve yields a remarkable correlation be-tween the frequency patterns and load gradi-ents, i.e. positive load gradients correspond to frequency deviations “up” and vice versa, see yellow and green areas in Figure 4. For both directions, the magnitudes of the frequency deviations directly depend on the correspond-ing load gradients. This applies for the whole course of day. Similarly, also the load and fre-quency behaviour within the summer months have been investigated leading to the same re-sults.

Current Practice of Load Coverage of the Market Participants

The current practice of the different market participants with respect to the interaction of power trade and power system operation is schematically shown in F i g u r e 5 . The eval-

uation was based on the German market model and may differ in details for market models implemented in other European coun-tries. However, the dominating influence of a harmonised pan-European deregulated energy market with a power trade mainly in 1-h-inter-vals applies for all countries or control areas respectively.

Current Practice on the Demand Side Figure 5 (left-hand side)

Balance responsible parties (BRPs) on the de-mand side prevalently carry out the load fore-cast in ¼-h-intervals. From this, they create schedules mainly in step-wise 1-h-intervals. These schedules are on the one hand the start-ing point for ordering power products in the power market, on the other hand they are an-nounced to the TSO within the framework of the given time limits [6], consequently provid-ing four equal ¼-h-power values for each 1-h-interval.

For each BRP, the energy deviation between the mainly ramp-wise changing physical load and the ordered constant 1-h-products is set-tled on a ¼-h-basis. The resulting control en-ergy costs are initially borne by the BRPs.

Current Practice on the Generator Side Figure 5 (right-hand side)

The energy deviation for the BRPs on the generator side is given by the difference be-tween the ordered power products and the ac-tual generated power, which induces the aim of the generators to follow the ordered sched-ule as close as possible to keep the control energy costs on the generator-side low. This behaviour leads to partially high step-wise changes of the actual generated power, espe-cially if pumped-storage plants are available.

Current Practice on the TSO Side Figure 5 (bottom)

The TSO receives the schedules from all BRPs day-ahead within the given time limits which incorporate the expected course of load and generation apart from intra-day trading, and checks their integrity. Generally, the TSO de-mands schedules in ¼-h-intervals. Neverthe-less, since the schedules emerge from the power trade which is mainly based on 1-h-in-tervals, they de-facto consist predominantly of four equal ¼-h-values for each 1-h-interval.

To balance power deviations between genera-tion and consumption, the TSO utilises differ-

Balancing area(demand side)

load-forecast/standard load profiles

6:00 h 7:00 h

PL

Load-forecast

BalanceResponsibleParty (BRP)

Requiredcontrol energy

EL

0

6:00 h 7:00 h

e∆PLdt

∆PL

Actual load behaviourPL

6:00 h 7:00 h

Institution

Function

Deterministicpower imbalance

∆P

0

6:00 h 7:00 h

∆P

Primary control, secondary controlminute reserve

Activaton ofcontrol energy

6:00 h 7:00 h

PG 1-h-steps

Actual generation behaviour(excl. control power activaton)

∆PG

e∆PGdt

6:00 h 7:00 h

EG

PGact


Dispatching

Generators

6:00 h 7:00 h

PG

Power target value1-h-steps

Balancing area(generator side)

6:00 h 7:00 h

PG

Generator schedule1-h-steps

PGsch

Spot markets

PL

6:00 h 7:00 h

order1-h-steps

Sales, trading, OTC, etc.

PLschPL

act

PL

6:00 h 7:00 h

load schedule1-h-steps

TSOo PL

sch = PGscho

Figure 5. Current practice of load-coverage of the market participants.



a) Power imbalance curve in case of 100%-schedule-based dispatching

∆P[GW]

-15

-10

-5

0

5

10

15

+13 GW

-13 GW

00:00a.m

08:00Timep.m.

02:00 04:00 06:00 10:00 12:00 02:00 08:0004:00 06:00 10:00 12:00

∆load

Scheduled generation

Load following generation

PmaxÙ

Participation

ksch

1-ksch

PG* ∆P *

PL*

System self-regulating effect

kpf(S)

Rotating masses

TN

∆Ppr*

∆Psec*

kpr

ksec

f0*

fset*

f *

Pmax, PmaxÙ 100�dpr

oPrimary control

oSecondary control

b) Simple dynamic model for the summarised power system behaviour

50.5

f [Hz]

50.2

50.0

49.5

49.8

00:00a.m

08:00Timep.m.

02:00 04:00 06:00 10:00 12:00 02:00 08:0004:00 06:00 10:00 12:00

c) Deterministic fequency part for the postulated case of 100 %-schedule-based dispatcing

+400 mHz

-400 mHz

fsim, 100%˜

Figure 6. Load and frequency behaviour for the postulated case of 100 %-schedule-based dispatching.



ent mechanisms of load-frequency control, namely primary control, secondary control and tertiary control.

Since the primary and secondary control mechanisms are based on solely feed-back control loops, they can only inertially react to the occurrence of step-wise power imbalanc-es. Hence, the power balance between genera-tion and consumption can only be re-estab-lished after a certain time delay.

Tertiary control, namely the activation of minute reserve power, is invoked by the TSO in advance, which provides a certain feed-forward control mechanism. Because minute reserve power must generally be available at very short notice, i.e. at any time up to 7.5 minutes before the following ¼-h-interval, it is a valuable and therefore expensive re-serve power product. Furthermore, the TSO bears the cost risk of a possible erroneous ac-tivation.

S imula t ions o f t he Frequency Behav iour

The following analysis is based on the system behaviour during the winter months. The cor-responding analysis of the summer months leads to equivalent results.

Frequency Behaviour in the Case of 100 % Schedule-based Dispatching

Considering the case of 100 % schedule-based dispatching, which actually proves necessary to be consistent to the deregulation and liber-alisation process [7, 8] the resulting step-shaped scheduled generation curves covering the same energy amount as the continuous load curve are included in Figure 4b. For the subsequent investigation, the load PL is sub-tracted from the scheduled generated pow-er PG,sch, which yields the deterministic power imbalance also shown in Figure 5 (bottom) as input of the load-frequency control.

Based on actual load data from the UCTE power system [5] the resulting power imbal-ance within the European power system would reach up to ∆Pmax = ±13 GW ensemble-aver-aged over the six winter months as can be seen from F i g u r e 6 a . At individual days the power imbalances even rise up to ∆Pmax = ±19 GW. The dimension of these large power imbalances, which reach more than four times of the total primary control reserve power of 3 GW within the European power system, and their impact on the frequency behaviour can now be shown via simulation.

For this purpose a simple dynamic model for the summarised power system behaviour is used, see Figure 6b. The model includes the system self-regulating effect as well as the summarised impact of primary and secondary control and is suitable to compute the fre-quency behaviour for a given summarised power imbalance curve.

Modifying the participation factor ksch, the proportion of generators behaving stepwise can be adjusted. For the postulated case of 100 % schedule-based stepwise dispatching, the model proportion factor is set to ksch = 1. For realistic results the system self-regulating effect is set to kpf

(s) = 1.5 %/%, and the gradi-ents of the schedule-induced power steps are limited by applying a maximum gradient of 20 %/min.

The resulting deterministic frequency behav-iour f

,

sim,100% caused by the schedule-based power imbalances is shown in Figure 6c, lead-ing already to maximum frequency deviations of up to 400 mHz. For the worst case consid-eration with kpf

(s) = 0.5 %/% [4] the deviations of f

,

sim,100% even reach up to 550 mHz.

The occurring power imbalances are initially balanced by the rotating masses as well as by the instantaneous impact of the system self-regulating effect and the activation of primary control reserve power. After 10 to 15 minutes the power balance is finally achieved by the secondary control which is activated within all control areas in the same direction in the considered case.

Actual Frequency Behaviour in Case of 20 %-Schedule-based Dispatching

According to actual measurements, occurring frequency deviations only reach magnitudes in the range of ∙∆f∙ = 150 mHz. The reason is that the dispatching of power plants within the European power system today is based on a mixture of three operation modes:

100 % schedule-based dispatching re- –producing the schedule steps as close as possible,

schedule-based dispatching, however, by –continuously incorporating additional avail-able information concerning load and sys-tem state to minimise costs emerging from the financial settlement of control energy, and

“classic” load-following operation, not –based on schedules.

Therefore, a much smaller proportion of schedule-based dispatching can currently be

expected within the European power system. With an estimated proportion of ksch = 0.2, the simulation leads to the frequency curve shown in F i g u r e 7 , which shows a good agreement with the measured frequency curve ensemble-averaged over the winter months.

The simulation results demonstrate that the conditions emerging from the current market boundaries and system rules for the deregu-lated electric energy market lead to the ob-served large frequency deviations, despite the correct impact of the load-frequency control mechanisms.

Based on these findings, an improvement measure and proposals for its realisation have been developed in co-ordination with the steering committee of the research project. The incorporated proposals have been dis-cussed in detail with all market participants, i.e. BRPs, TSOs, traders and generators, to ensure their practicability and effectiveness as far as possible.

Measure

To reduce the occurring large power imbal-ances, the actual power output on the genera-tor side has to match the physical load behav-iour better than today, where the approxima-tion of the physical load is only accomplished based on 1-h-intervals due to current market conditions and available power products.

Therefore, measures have to entail improved system rules for the market participants to reach a better accordance of generated and consumed power and to avoid high stepwise power changes on the generation side, i.e. to compensate the power imbalance ramp ∆Pramp(t) in time or to prevent its emergence at all. This at this stage exclusively technical requirement is shown in F i g u r e 8 .

P roposed Measure : “4 -qua r t e r- s t eps” -p roduc t

To compensate the “power imbalance ramps”, counteracting “power balancing ramps” are

50.10

f [Hz]

50.05

50.00

49.90

49.95

00:00a.m.

08:00p.m.

02:00 04:00 06:00 10:00 12:00 02:00 08:0004:00 06:00 10:00 12:00

fsim, 0.2˜

fmeasured˜

Time

Figure 7. Deterministic frequency part: – simulated for 20 %-schedule-based dispatching – ensemble-averaged measurements, winter months.



required, which can be approached by four power steps covering a ¼-h-interval each, ac-cording to the framework given by the current settlement period of 15 min. The heights of the four steps can be standardized to create a well-defined new power product, which will be referred to as “4-quarter-steps”-product in the following.

The “4-quarter-steps”-product has the aim to keep the 1-h-time period which is already well established in the power market, but to distrib-ute the power target value into four equally climbing or falling ¼-h-steps within each 1-h-time period, (F i g u r e 9 a curve (1)). There-fore, only two power set point values at the beginning and end of each 1-h-time period are required. The resulting four different power target values are already closer to the physical ramp-wise changing load than the constant 1-h-products represented by curve (0) in Fig-ure 9a.

Subsequently, the “4-quarter-steps” can be transformed into ramps on the generator side without causing an energy deviation and hence without additional costs arising from the control energy settlement. The ramps start 7.5 minutes before the step and end 7.5 min-

utes2 after the step (Figure 9b). The resulting 1-h-ramp, see Figure 9a curve (2), is equiva-lent to the generation behaviour during the classic load-following operation, but never-theless schedule-based and hence capable of being integrated within the deregulated ener-gy market, since the described concept leads to 1-h-ramps covering the same amount of en-ergy as the constant 1-h-product.

Simulations show that the “4-quarter-steps”-products eventually have to be realised as 1-h-ramps on the generator-side, since otherwise four steps with a quarter of the amplitude re-spectively would occur, stressing the primary controlled power plants continuously.

Remarks on alternative proposals Market-wide Change-over to ¼-h-products

Independent ¼-h-products would have to be traded 96 times per day. Hence, associated disadvantages emerge from possibly very un-settled schedules not leading to the required 1-h-ramps as well as from a resulting higher complexity and corresponding need to adapt the trading tools.

2 The TSOs already transfer stepwise scheduled changes of power exchange programmes to ramps on control area level with a ramp duration of ± 5 min [7].

Increasing the Quality of Load-frequency Control

Since the primary and secondary control mechanisms are based on solely feed-back control loops which can only inertially react to the occurrence of stepwise power imbal-ances, an improvement of the control quality can at best slightly reduce the frequency de-viations.

It should be noted in this context that the im-pact of the primary and secondary control mechanisms according to the present rules is already included in the performed simulations shown in “Analysis of the Origins of the Fre-quency Deviations”.

Proposals for Realisation

For the practical realisation of the above de-scribed “4-quarter-steps”-concept two com-plementary proposals have been developed. They are comprehensively shown in F i g - u r e 1 1 , which is based on Figure 5 and F i g u r e 1 0 .

P roposa l 1 : Rea l i s a t ion on the Demand S ide

Description

Proposal 1 aims at creating improved possi-bilities for BRPs on the demand side to ap-proximate their load also with ¼-h-steps and to order respective power products3. The ac-cording financial incentive for the BRPs lies in the reduction of the required control energy. This advantage will gain importance if the prices for control energy further increase.

The consumers of electrical energy can gener-ally be classified into the following areas, the respective fractions given for Germany [10]:

households (26.5 %) –

business and service sector (28.5 %) –

industry sector (45 %) –

Since the BRPs on the demand side normally have to perform a load forecast, they know “their” expected individual load behaviour, mostly already in ¼-h-steps. Furthermore, for households or the business and service sector, often used “standard load profiles” are given in ¼-h-steps as well [11]. In case the load behav-iour is not available in ¼-h-steps, the 1-h-sched-ules can be transformed into ¼-h-schedules by applying pre-defined algorithms leading e.g. to subsequent rows of “4-quarter-steps”.

Schedule steps remain further possible, e.g. for the case of stepwise behaving load changes in industrial productions, as the end power tar-get value within one 1-h-interval does not have to be equal to the start power target value with-in the subsequent 1-h-interval.

3 It should be noted that covering the load with ¼-h-steps leads to a higher resolution of the ordered power products, but not necessarily to a higher load forecast accuracy

a) Power imbalance during increasing load b) Power imbalance during decreasing load

6:00 a.m. 7:00 a.m. 6:00 p.m. 7:00 p.m.

PLPG, sch

∆Pramp (t) = PG, sch–PL

PL PG, sch

∆Pramp (t)

Time Time

Figure 8. “Power Imbalance Ramps” for increasing and decreasing load.

a) 4-quarter-stepsPL, 2

PL, 0

PL, 1

0

(0) constant 1-h-product

(2) resulting 1-h-ramp

(1) “4-quarter-steps”

2T = 15 min

7:00 h6:00 he.g.

b) realisiation as ramp

∆Pref (t)

∆P ∆Ptarget

∆Pd (t)Tpp

2T = 15 min

tti-1 ti-T ti ti+T ti+1

Figure 9. 4-quarter-steps and their realisation as 1-h-ramp.



Ordering “4-quarter-steps”-products on the Demand Side

The BRPs on the demand side can order “4-quarter-steps”-products, i.e. 1-h-products with variable start and end power target val-ues, already today, e.g. in the OTC-market.

The advantage from the system point of view is the inclusion of the required power balanc-

ing ramps inside the ordered power products already at an early stage (“counteracting the cause”).

Since the settlement of control energy is based on ¼-h-intervals already today, no further changes of rules are necessary.

If proposal 1 is not applicable to all BRPs, e.g. in case not enough reasonable priced

“4-quarter-steps”-products are available, the remaining power imbalance ramp has to be compensated by the TSO. Hence, proposal 1 only refers to a certain load fraction “α”, see Figure 10 and Figure 11.

P roposa l 2 : Rea l i s a t ion on the TSO S ide

Description

Proposal 2 is targeted on a relocation of con-trol work from the only delayed reacting feed-back control loops of the load-frequency con-trol to a new feed-forward control mechanism (“counteracting the symptom”).

For this purpose, the TSO orders the required power balancing ramps ∆Pfeed-forward in a sep-arate “balancing-market”, see Figure 10. Sim-ilar concepts have already been implemented individually in other control areas within the UCTE power system, e.g. in Italy and Poland [12, 13].

Determination of the Required Power Imbalance Ramps

To determine the required power balancing ramps in advance, a forecast of the load be-haviour is required. For this purpose, two al-ternatives are possible.

Balancing area(demand side)

load-forecast/standard load profiles

6:00 7:00

PL

Load-forecast

BalanceResponsibleParty (BRP)


EL

0

6:00 7:00

e∆PLdt

∆PL

Actual load behaviourPL

6:00 7:00

Institution

Function

Deterministicpower imbalance

∆P

0

6:00 7:00

∆P

Primary control, secondary controlminute reserve

Activaton ofcontrol energy

6:00 7:00

PG

Actual generation behaviour(excl. control power activaton)

∆PG

e∆PGdt

6:00 7:00

EG

PGact


Dispatching

Generators

PG

Balancing area(generator side)

PG

Generator schedule

PGsch

Spot markets

PL

Sales, trading, OTC, etc.

PLschPL

act

PL

load schedule

TSO

Load Fractions a+b:4-quarter-steps

PLf

Load Fraction a:4-quarter-steps

Load Fraction b:1-h-Product

order

„Balancing Market“

power balancing ramp ∆b+∆g

for load fractions b and g∆PG

0

feed-forward control

Load Fractions a+b+g:4-quarter-steps

Load Fractions a+b+g:4-quarter-steps

power target value

o PLscho=∆PG

feed-forward 6PLf – + PTSO

f o– PLf = PTSO

f o– PLsch6

(power balancing ramp ∆b) (power balancing ramp ∆b)

load forecast “control area”

Figure 10. Integration of the required power balancing ramp in the current practice of load-coverage of the market participants.

Load-forecastActual load behaviour

BRP on the demand side TSO GeneratorOrdered powerproductannounced schedule1)

Power balancingramp

Power target valueActual generation behaviour

PL

(1)

a)Load

fractiona

b)

c)

Loadfraction

b5b0+∆b

g5g0+∆g

Loadfraction

PL

PL

PL

b0

g0

0

0

0

Power bal. ramp ∆b

Power bal. ramp ∆g

∆PG

∆PG

∆PG

PG

(1)

(2)

1) The announced schedule is still the basis for the settlement of control energy

Figure 11. Comparison of the proposals for covering the ramp-wise power imbalances.



a) Alternative 1 (Figure 10, indicated red)

To utilise the load-forecasts from the demand side, the BRPs have the option to announce additional schedules to the TSO which repre-sent the expected load behaviour in ¼-h-intervals. Hence, they already incorporate

the load fraction “ – α”, which is covered by “4-quarter-steps” as well as

a further load fraction “ – β”, which is cov-ered by conventional 1-h-products ordered in the power market (Figure 10 and Fig- ure 11).

The TSO sums up all additional announced schedules PL

f. The difference between the re-sulting summarised schedule ΣPL

f and the schedule ΣPL

sch resulting from the power trade yields a power imbalance ramp which can be compensated by the TSO by ordering a corre-sponding power balancing ramp “∆β” already day-ahead. With this approach, the TSO bears no responsibility regarding the accuracy of the load forecast but only manages the order of the power balancing ramps.

The settlement of control energy occurs on basis of the additional provided ¼-h-schedules . The settlement of the power bal-ancing ramps ordered by the TSO is done separately on basis of their acquisition costs. Thus, the total control energy costs for the BRPs on the demand side are lower than the otherwise emerging costs for the total amount of control energy without day-ahead ordered power balancing ramps.

b) Alternative 2 (Figure 10, indicated green)

Furthermore, the TSO has the possibility to order additional power balancing ramps “∆γ” resulting from the difference between the an-nounced summarised schedule ΣPL

f an-nounced by the demand side and the load-forecast Pf

TSO by the TSO on control-area lev-

el, see Figure 10 and Figure 11c. The settle-ment of control energy for each BRP is again carried out on basis of the announced sched-ule PL

f as for Alternative 1.

The advantage of this approach emerges from the load-forecast on the higher control area level, which leads to a better averaging effect and hence a better forecast accuracy. The costs for the additional power balancing ramps “∆γ” are passed to the BRPs within the frame-work of the common control energy settle-ment. Thus, the control energy costs for the BRPs are the higher, the further their addi-tional announced ¼-h-schedule PL

f including the load fractions “α” and “β” differs from the real load behaviour.

In case only the load forecast on control area level is used for determining the required power balancing ramps and the control energy settlement, the load fraction “β” becomes zero.

Ordering of “4-quarter-steps”-products by the TSO

The required power balancing ramps can be ordered in a separate “balancing market”, where generators can place respective bids based on ¼-h-intervals.

The tenders lead to ¼-h-schedules for the generators which are available at an early stage, e.g. day-ahead until 6 p.m. Due to this early availability of the schedules, the price of the power balancing ramps will be considera-bly lower than an expensive activation of a corresponding amount of control energy.

Tabu la r Comprehens ion o f t he P roposa l s

The respectively ordered power product and announced schedule for the different load fractions “α“, “β” and “γ” of the total load and the corresponding formation of the power balancing ramps are comprehensively shown in Figure 11.

The following extreme cases can be derived:

“α“ = 100 %: The entire power balancing ramp is included in the market order and hence in the announced schedules. The TSO does not do anything.

“β“ = 100 %: The BRP on the demand side exclusively order 1-h-products with a constant power target value, however, announce a ¼-h-schedule. This schedule is the basis for the settlement of control energy on the one hand and for the order of the power balancing ramp by the TSO on the other hand. The TSO settles the acquisition costs for the power balancing ramps in addition to the settlement of control energy (balancing market price).

“γ“ = 100 %: The TSO orders the entire power balancing ramp based on the load-forecast on control area level and settles their costs within the framework of the settlement of control en-ergy (control energy price). The BRPs on the demand side do not do anything, i.e. only an-nounce 1-h-schedules.

Expec ted Impac t s o f t he P roposed Measures

The described proposals establish an informa-tion flow containing the expected physical load behaviour from the demand side to the generation side.

This necessary information flow is currently broken since the generation side only covers market orders in 1-h-intervals without taking into account the corresponding real physical load behaviour.

Proposal 1 leads to a direct information flow, since the respective power balancing ramps are already included within the ordered “4-quarter-steps” power products covering the load fraction “α”, while proposal 2 results in an indirect information flow through the or-

dered power balancing ramps “∆β” and “∆γ” in the balancing market. As a result the physi-cal behaviour of the generator side approxi-mates the “classic” load following operation while entirely being compatible to the rules and principles of a deregulated energy mar-ket.

Regarding the individual market participants, the following benefits can be expected:

Demand side:

Reduced costs for control energy –

TSO side:

Avoidance of large power imbalances al- –ready during load coverage on the demand side (proposal 1), subsequently reduced ac-tivation of control energy,

Relocation of conventional control work, –which otherwise would be activated to com-pensate the large power imbalances, to a cost-eff icient feed-forward-mechanism (proposal 2); hence reduced total control energy costs.

Generator side:

Less power plant stress due to lower re- –quired power gradients during load chang-es,

Reduced intensity of primary control power –activations in primary controlled power plant units due to reduced frequency devia-tions, both with respect to their magnitude and number of occurrences.

Conclusion

Long-term evaluations of the frequency be-haviour within the European power system show that the increasingly large frequency de-viations occurring mainly at the change of the hour affect power plant and power system op-eration already today. It was shown that the power imbalances are system inherent accord-ing to the actual rules of the deregulated elec-tric energy market. Counteractive measures have to lead to a better adjustment of the mar-ket based stepwise scheduled generated power to the physical load behaviour than it is the case today.

As concrete improvement measure, an ap-proach of the current stepwise 1-h-schedules to the ramp-wise changing actual load behav-iour four equal ¼-h-steps is proposed. The realisation of this measure can be implement-ed both on the demand-side and/or on the TSO-side. For this purpose two complemen-tary proposals have been developed which are advantageous for all market participants through

decreasing the required amount of control –energy and hence reducing the respective costs on the demand side,



reducing the control work and improving –the control performance of the UCTE pow-er system, ensuring sufficient primary con-trol reserve power at all times,

reducing the required power gradients on –the generator side, hence reducing the stress of the power plant units.

The proposals contain the input of all market participants obtained during various discus-sions. Since all market participants are con-cerned, a concerted implementation of coun-ter measures should be aspired.

Last but not least, it should be noted that similar measures leading to a modification of the power schedules arising from the elec-tric energy market have already been imple-mented within individual control areas like Poland and Italy. Looking at the example Po-land, the TSO creates a ¼-h-schedule based on a special balancing market, which not only incorporates the market schedules, but also technical boundaries given by the power system itself with respect to its stability and security.

Since the highlighted issue is a European one, all European system players have to be included in the implementation of measures improving the control performance of the interconnected power system. Based on the project results, the VGB intends to put the proposed measures up for discussion both on a national and European level in co-operation with the BDEW and the EURE-LECTRIC.

Otherwise, without the implementation of measures to reduce the power imbalances, a

further increase of the frequency deviations with a highly negative impact on power plant and power system operation can be expected.

References

[1] Sattinger, W.: Monitoring of Power System Op-eration. VGB Workshop 4th ETC Generation and Technology – Impact of Grid Management on Power Plant Operation, 15 October 2008, Köln.

[2] UCTE: UCTE Ad-hoc Group “Frequency Quality Investigation”, Excerpt of the Final Re-port. www.ucte.org, 2009.

[3] Weißbach, T., Kurth, M., Welfonder, E., Schulz, U., Heidrich, W.: Rückwirkungen des Netzstör- und Führungsverhaltens auf den Kraftwerksbe-trieb. VDE-Kongress 2006, Aachen.

[4] UCTE: UCTE Operation Handbook, 2004.

[5] UCTE: Database on www.ucte.org, 2008.

[6] Stromnetzzugangsverordnung (StromNZV), 2005.

[7] EU (2003).Directive 2003/54/EC of the Euro-pean Parliament and of the Council of 26 June 2003.

[8] EU (2007). Proposal for a Directive of the Eu-ropean Parliament and of the Council amend-ing Directive 2003/54/EC concerning common rules for the internal market in electricity. 19 September 2007.

[9] Kurth, M., Welfonder, E.: Importance of the self-regulating effect within power systems IFAC Symposium on Power Plants and Power System Control 2006, Kanaskis, Canada.

[10] VDE-Studie “Effizienz und Einsparungspoten-tial elektrischer Energie in Deutschland – Per-

spektive bis 2005 und Handlungsbedarf. VDE 2008.

[11] BDEW (2008) Standard Load Profiles. Bun-desverband der Energie- und Wasserwirtschaft, www.bdew.de

[12] Mielczarski, W., Siewierski, T., and Wedzik, A.: Experience from the Operation of the Polish Electricity Market. IEEE Xplore 2005.

[13] Terna. Code for transmission, dispatching, de-velopment and security of the grid and ap-pen-dices. Terna - Rete Elettrica Nazionale SpA, 2007.

Appendix: „Practical Example“

Within a control area the BRPs on the demand side predict 80% of their load behaviour by ¼-h-steps, but only a fraction of α(t) = 50% can directly be ordered as “4-quarter-steps”-product on the energy market. The rest, i. e. β0 = 30 % and γ0 = 20 %, must further on be ordered as 1-h-steps.

However, the corresponding BRPs announce the load fractions α(t) and β(t) as ¼-h-schedule to the TSO, who will buy a power balancing ramp of ∆β(t) = 30% on behalf of the consumers on the balancing market.

For minimizing the total cost for control en-ergy the TSO can order a further balancing ramp of ∆γ(t) ≤ 20 % on his own responsibil-ity.

Therein the “power balancing ramps” are also scheduled as “4-quarter-steps”, which are transformed to ramps on the generator side, c.f. Figure 9 to 11. h

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High Frequency Deviations within the European Power System

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