Dimensioning of the operating reserves in systems ...

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Dimensioning of the operating reserves in systems with Wind power generation *OANA UDREA, **GHEORGHE LAZAROIU, ***EMIL M. OANTA, CORNEL PANAIT * Transelectrica S.A., **University Politehnica of Bucharest, ***Department of General Engineering Sciences Constanta Maritime University *2-4 Olteni str., Bucharest, 030786, **Splaiul Independenței 313, Bucharest, 060042, ***104, Mircea cel Batran str, Constanta, 900663 ROMANIA [email protected] , [email protected] , [email protected] , [email protected] Abstract: - One of the main problems facing operators of electrical systems that include nonconventional generation is establishing the dimension necessary for the balancing services of the system, keeping in mind that the working conditions of the different technologies can significantly modify the behavior of the characteristics of the mix, in such a way that its response, in both normal operating conditions and in the event of oscillations, can also change substantially. Integration of renewable energy sources (RES) has several complex aspects: grid integration, power system integration, social and economic impact, etc. In this article the focus will be the analysis based on the classic theory of transient stability of the power systems, which will try to determine a first limit of the proportion of synchronous inertial generation that a system would require to remain stable in the event of a certain incident (study of one single node).

Key-Words: - wind farm, grid, balancing market, electrical system, renewable. synchronous system in order to operate, no matter a series of requirements can be requested once the operating condition is established, always based on the primary resource available. Keeping in mind that there is a technical limit in any case, since the generation based on asynchronous systems requires a pre-existing synchronous system in order to operate, no matter a series of requirements can be requested once the operating condition is established, always based on the primary resource available. As the presence of non-conventional generation has become more important, studies have been appearing that try to quantify the needs. In particular, and regarding the wind power generation, the manufacturers associations tend to minimize the problem for the current installation levels, also ensuring that the technology, based on power electronics, is able to provide voltage and power regulation similar to that of the conventional machines (at the moment even the capacity to “emulate” the inertial behavior is being discussed); on the other hand, the analyses of the operators usually refer to the statistical experience not being complete, and to the necessity of applying conservative criteria in order to guarantee secure and stable operation.

1 Introduction The balancing services of the system are a set of resources available to the operator in order to ensure the operating of the electric system under suitable conditions, and they can be summarized according to the following:  The solution of technical restrictions, in other words, the adaptation of the initial programs coming from the electricity markets (longterm contracting, daily and intraday markets) and the solution to restrictions in real time.  The ancillary services: those associated to the frequency-power regulation (primary, secondary and tertiary regulation), the voltage control and the participation in restoring the system.  The load-generation deviation management processes. When non-conventional generation is also based on a foreseeable primary resource up to a certain point but is essentially random, it takes on special importance when determining if the operation has the proper means to deal with its variability, during the daily operation (balancing services) as well as in the mid to long term (long term adequacy studies). Keeping in mind that there is a technical limit in any case, since the generation based on asynchronous systems requires a pre-existing

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

An example of the view from the side of the system can be found in the document published by NERC [1], in order to explain why the presence of wind power generation supposes the need for greater flexibility in the operation of the system.

Very fast variations (from seconds to minutes): caused by turbulence or transient phenomena, EWEA believes that it has a small effect on the system due to the aggregation of turbines in the wind farms.[6] NOTE: a significant source of rapid variations may be the trips due to voltage dips in the network.  Variations within the hour (hourly ramps): they can have a significant effect on the system, EWEA states that in normal conditions they should not be higher than ±5% of the installed power; mentioned as the most problematic case, the disconnection of generators due to excessive wind speed during storm fronts, using the extreme example of the storm of January 8 2005, which caused a significant generation loss (from 2,000 MW down to 200 MW) in a couple of hours in Denmark, with ramps of 5 MW/minute. For EWEA, these effects would only be significant from 5-10% of the annual energy supplied by wind power.  Variations in hourly periods are attributed to forecasting errors and can affect the daily generation dispatch; in order to EWEA, the variation is not as important as the magnitude of the error.[4]

Fig.1: NERC. Wind power generation as “negative demand”[1] In Fig.1, the red area represents the demand and the blue area represents the sum of the demand minus wind power generation, in other words, wind power generation is considered to be a "negative demand". For NERC, this means that more conventional generation must exist that is able to follow the new aggregate demand curve, which now adds two different variability sources: that of the demand and that of the wind power. Fig.2 shows an estimate of different sources on the increase of the reserve needs in the system.

2 Main characteristics of electricity system in Romania

From the information provided by Transelectrica, the electricity market in Romania operates largely through bilateral contracts (8590%), leaving the daily market with approximately 10% of the contracting. There are no intraday markets.[16] The system operator resolves the technical restrictions of the daily market with a balancing market, whose products are secondary and tertiary energy, which manages energy of 2-6% (over the total contracted). In addition to a market for the provision of ancillary services (Ancillary services market), there is another market for the provision of an additional reserve (Capacity reserve market) for extreme conditions (extreme temperatures, trips of thermal units). Lastly, there is a market for green certificates, in order to promote energy supplied by renewable sources. All units greater than 50 MW (apart from the back pressure thermal units and nuclear plants) and certain hydro power plants between 10 and 50 MW

Fig.2: Estimated impact of wind power generation on the system's reserve requirements. [2] It is important to emphasize that the effect of the variations is not an instantaneous problem (since the requirements have established that the wind energy installation must remain connected in the event of voltage dips); it is a problem of ascending and descending power ramps, which can appear in a variable period, in one hour, or in several hours. In accordance with the document "Wind Energy: The Facts” by EWEA [3], the wind variations can be classified in the following time periods:

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the

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have the primary regulation enabled, the majority are capable of providing 100% of the required reserve before 30 s.[19] The master regulator of the secondary regulation will act on 8 hydro power plants and 4 thermal power plants. In order to cover the sudden loss of the largest generation group a rapid reserve (minute reserve) is activated, which can act in less than 15 minutes, composed of secondary, spinning and rapid tertiary reserves; the total is 706.5 MW (= Group 1 power of the Cernavoda nuclear power plant). The secondary and spinning reserve is supplied by hydraulic and thermal units in operation, whereas the rapid tertiary reserve is supplied quick-start hydraulic units.[20]

controlled by electronics, either doubly-fed asynchronous machines or synchronous machines with a converter in the stator; secondly, that there is no inertial contribution by these machines and that they do not have any control strategy in this sense. The assumption that the wind machines will be controlled by electronics, and will not be squirrel cage induction machines, is a reasonable hypothesis, first because of the functioning of the majority of the current machines, and second because they need this control type to satisfy the requirements set out in this report. As for the second condition, when assuming that the controlled wind machines do not contribute any inertia to the system, it is assumed that the control strategies in the doubly-fed machines are dedicated to the electric rotor speed control based on the wind variability, to prevent mechanical problems, and therefore they cannot allow the free cession of the kinetic energy stored in the electric rotor; it is also assumed that they do not have any additional control strategy for “inertia emulation” (variation of the output power based on the derivative of the deviation of the frequency). (According to the information sources consulted, this strategy is still not implemented by any manufacturer at the commercial level). As for the synchronous machines with a converter in the stator, naturally decoupled from the network, it is supposed that they also do not have this control strategy. In other words, it is assumed that only the synchronous components of the system are going to participate with their inertia in the transient stability process. The analysis is based on the resolution of the basic oscillation equation without considering damping terms. The incident is made up of three phases:  Phase 1, steady state, where the system operates in synchronism, with generation demand balance, i.e. the power supplied by the turbines (Pt) is equal to the electric power of the generators (Pg), and the internal angle of the machine is constant.[9]

3 Limit of inertial synchronous generation /asynchronous generation in order to maintain the transient stability of the system (study of one single node) This section establishes a first limit to the asynchronous generation that an inertial synchronous system can accept following the transient stability criteria, i.e. how much asynchronous generation not providing inertia can be allowed in the conventional inertial synchronous system. For this purpose a basic analysis of the system (one single node) is made, looking to determine the total inertia needs assuming that the system can be represented as an equivalent generator, subjected to a close three-phase fault, with tripping of the generator breaker and reclosure after a specified time, when the action of the protections has cleared the fault.[10] We can make the following general observations about the initial hypotheses: - The fault hypothesis is the most severe possible, the total collapse of the generation of the system. Any incident due to a lower value will be withstood. - It is assumed that the system will restore the voltage instantly when the fault is cleared, i.e. that it is also connected to another system that is large enough so that there is no noticeable voltage dip. - Throughout the process it is assumed that the asynchronous machines do not contribute to the inertial support. This hypothesis is conservative and assumes two things: first, that most of the wind energy technology to install is going to be machines

ISBN: 978-960-474-343-8

Pt  [

VfE Vf 2 sin( )  Xd 2

 1 1    sin(2 )]  0 (1)   Xq Xd 

The second term of the equation represents the electric power Pg.  Phase 2, the fault occurs and the generator breaker trips. In the first few moments the turbine speed regulator did not have time to act, and its mechanical power is constant;

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nevertheless, the electric power that the generator would contribute to the network is zero. Therefore, the machine will be subjected to acceleration, and the internal angle increases.

H d2 Pt   t  f 0 dt 2 

Pt  [

supplied during the acceleration phase is lower or equal to that of the deceleration phase, so that the internal angle, which increases in phase 2, decreases in phase 3 in a damped way and reaches a value within the static stability limit. The basic factors so that this occurs are the mechanical inertia of the generator/turbine equivalent set (which marks the ratio the internal angle increases at) and the time the acceleration phase lasts, which has a lower limit, since the protection system needs time to act. This minimum time is established at 250 ms for the first analysis, assuming breaker failure. We still have to determine the inertia factor, expressed as the constant H (total kinetic energy expressed in the power base, MVA). The analysis has been made with an iterative process, in which H values have been tested until the desired result was obtained. The Fig.4 shows the solution obtained for H= 3.6 s and Pt=1 (system at 100% load, peak hours, assuming that the generation is also operating at full load). (In MW, Pg=9,100 MW; generation data from 15.12.08, document “The cover of the daily load curve”. Total power generated by nuclear plants, thermal and hydraulic plants without interchange). Phase 1 Pt=Pg=cte=1;  0 = 0.73 rad Phase 2 t= 0 – 250 ms

(2)

Phase 3: after a certain time, when the protection system has cleared the external fault, the generator breaker is reclosed and the electric power is generated again, but following a transient characteristic, until the steady state is restored. This transient power is higher than that existing in phase 1, which is why the machine is subjected to deceleration (it is assumed that the turbine speed control has not yet been applied and that the mechanical power remains constant), and the internal angle decreases. VfE trans Vf 2 sin( t )  Xd trans 2

 1 1  H d2    sin(2 t )]   t  f 0 dt 2  Xq Xd trans 

(3)

The Fig.3 graphically shows the shape of the Pt (constant) curve, the Pg curve in steady state and the Pg curve in transient regime, where the variable  int represents the internal angle of the machine.

Fig.4: Evolution of the internal angle and of its first derivative in phase 2[12]

Fig.3: Mechanical power Pt, steady state Pg and transient Pgtrans electric power.[11]

As you can in the figure, the internal angle and its derivative are increasing; the system accelerates having lost the “brake” applied by the electric power. At 250 ms, this curve is left in order to study phase 3. Phase 3 t > 250 ms

The system is initially found at the indicated point, where Pt=Pg=1 (100% load), with an internal angle of  0 . (The  critical angle will be used in the calculation process; it represents the angle in which the transient electric power equals the mechanical power; if it was exceeded during the transient process, it would inevitably give rise to a loss of synchronism). A necessary condition so that the system restores the stable balance is that the energy

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250 ms considered. The hypothesis of H=3.6 is therefore not an excessively conservative value for a maximum clearing time of 250 ms.[17] The process is repeated for Pg=0.83 (6,543 MW, summer peak situation), Pg=0.71 (7,597 MW, winter off-peak situation) and Pg=0.61 (5,556 MW, summer off-peak situation) with the following results: Table 1 1.00:

 0 = 0.730 rad  crit =3.023 rad  max = 2.350 rad Tmax 0.272 s

for H= 3.6 s

0.83:

 0 = 0.587 rad  crit =3.060 rad  max = 2.420 rad Tmax

Fig.5: Evolution of the internal angle and its first derivative in phase 3

for H= 2.4 s

0.258 s

for H= 1.9 s

0.257 s

for H= 1.5 s

0.72:

 0 = 0.501 rad  crit =3.061 rad  max = 2.469 rad Tmax

As you can see in Fig.5, the internal angle decreases along with its derivative, the system will regain stability. As verification, the equality of areas condition is applied, calculating the maximum permissible time to wait for reclosure (  max ) for phase 2 in these conditions (the time of 250 ms has been set arbitrarily). The  critical value will be determined first, which in this case is 3.023 rad. Acceleration area = integral under the curve Pt=cte up to an angle  max .

area _ cc( max )  Pt ( max   0 )

0.260 s

0.61:

 0 = 0.419 rad  crit =3.075 rad  max = 2.520 rad Tmax

The results are a representative envelope of situations from maximum generated power to minimum generated power, and determine certain minimum inertia H requirements (H has been adjusted to the limit of the clearing time, 250 ms). Once the minimum H values are obtained, it is possible to establish certain assumptions about the generation mix, the following average values from the data from Transelectrica [20] are considered:  Nuclear: H = 14.30 s  Thermal (mean value coal + fuel/gas): H = 7.66 s  High-capacity hydropower plant: H = 5.66 s

(4)

Deceleration area = integral between the transient Pg curve and constant Pt between  max and  critical .

It is considered that the rest of the groups do not contribute inertia (this gives a margin, since the special thermal regime will contribute something). The relationship between the powers of each technology, their constants H and the total values are expressed as: Ptherm · Htherm + Pnuclear · Hnuclear + Phyd · Hhyd = Ptotal · Htotal Therefore, in order to establish if the system will have enough inertia, a generation mix hypothesis must be established for each one of the scenarios considered. In this case, the data of the generation curves were taken on 12.15.09 and 07.24.09:  Nuclear: the two groups always in service, 1,427 MW in winter scenario and 1,394 MW in summer scenario.  Conventional thermal plant: according to the information supplied by Transelectrica, minimum technical conditions must be respected in thermal generation, taking into account that the groups must start in off-peak

Fig.6: Areas of acceleration (phase 2) and deceleration (phase 3) as a function of the reclosure angle As you can see in Fig.6, there is an angle where both areas match; above this, the acceleration area is greater than the deceleration area, and so the system would not be stable. In this case  max = 2.350, which corresponds to a time of 0.272 ms; that is, not much more than the

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situation in order to be available in the next peak situation (Starting time of approximately 7 hours). Technical minimum are in general approximately 60 % of installed power.[18]

account the minimum limit in off-peak situation also in peak situation). In fact, if part of hydraulic generation is eliminated, the minimum inertia requirements continue to be satisfied (Table 4). It has been supposed that 30 % of initial hydraulic generation has been eliminated (value to be checked with feasible operating conditions in hydropower plants). Again, the result is conservative in off-peak situation, where, according to thermal generation conditions, the number of operating groups is higher than the assumption to obtain the calculated value.

With these conditions, and according to the curves from 12.15.09 and 07.24.09, in winter scenarios, it shall be considered 3,425 MW of minimum thermal and in summer scenarios 2,285 MW of minimum thermal in operating conditions.  Hydropower plants: according to the thermal generation conditions, hydropower plant could be stopped in off-peak situations.

Table 4 Availability of inertia with non-contributing generation eliminating thermal and hydro generation

First the "current" values will be verified; Table 2, and then the mix will be modified in order to add non-inertial generation (wind power).

Data Winter Winter Summer Summer

Table 2: Availability of inertia in current conditions Pg Pnuclear Ptherm Phyd Htotal MW MW MW MW S Winter 9,104 1,427 5,275 2,402 8.2 Winter 6,543 1,427 4,318 798 8.9 Summer 7,595 1,394 3,407 2,794 8.1 Summer 5,556 1,394 2,739 1,422 8.8 Data

The addition of wind power generation is made at the expense of the non-nuclear thermal groups, table 3, taking into account the technical minimum conditions. Table 3: Availability of inertia with noncontributing generation eliminating non-nuclear thermal generation

Winter Winter Summer Summer

4 Conclusion In view of the above, consideration of the following aspects is recommended. It is understood that it is taken as a starting point that it is not acceptable to reduce the current supply security conditions to favor the introduction of generation from renewable energy sources.  Determine a priori the degree of priority to be given in generation dispatch to wind production. Given that the functioning of wind power does not maintain any relationship with the demand curve, its operation depending on the wind resource is not always suitable for the system.

Pg Pnuclear Ptherm Phyd Pwind Htotal MW MW MW MW MW S 9,104 1,427 3,425 2,402 1,850 6.6 6,543 1,427 3,425 798 893 7.8 7,595 1,394 2,285 2,794 1,122 7.0 5,556 1,394 2,285 1,422 454 8.2

Again, the high inertia values of the nuclear power stations mean the minimum inertia requirements are still fulfilled assuming a minimum presence of the rest of thermal groups (taking into

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Pwind Htotal MW S 2,571 6.2 1,132 7.6 1,960 6.4 882 7.8

The previous results have to be interpreted along with the rest of the system requirements, for example:  The operating factors of the hydraulic plants  The preference of “spilling” water in river flow hydropower plants instead of “spilling” wind in the new wind installations, being both of them renewable energies (in case of hydropower installations with storage it is reasonable to store water when there is wind to produce energy)  The regulation needs. In Romania, the nuclear power stations do not take part in the primary or secondary regulation, and therefore it will be the rest of the generators that will assume this requirement.  Failure criteria (concentration of inertial generation in the nuclear plant, in the off-peak cases of Table 4).

The high inertia values presented by the nuclear power stations and the weight this generation has in the mix cause the minimum inertia requirements to be completely satisfied in the current conditions. (Besides, with these inertia conditions, in off-peak situations, real inertia availability would be higher than the calculated one, because there are more groups operating under reduced load condition. While the calculation has been developed considering the groups under a full or almost full load condition).

Data

Pg Pnuclear Ptherm Phyd MW MW MW MW 9,104 1,427 3,425 1,681 6,543 1,427 3,425 559 7,595 1,394 2,285 1,956 5,556 1,394 2,285 995

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Take into account the minimum inertial generation criterion, which in the case of Romania does not impose a special limitation due to the high weight of nuclear generation in the mix. It would be necessary to confirm that the inertia values used are correct, as the result depends essentially on this (especially for nuclear generation the data exceeds the values found in the information consulted). Determine a priori the reference incident (maximum wind power generation failure). Recommendation: 70% of the installed power. This assumption is conservative, but it must be taken into account that in Romania the generation will be concentrated in one area, which means the unavailability could have a common cause (atmospheric conditions). Determine a priori if the participation of wind power generation will be considered in the frequency-power regulation. Recommendation: request it as a connection requirement but decide the dimensions of the system reserves independently. This recommendation is based on the following reasons: The consideration of the reference incident (maximum wind power generation failure), which may have an atmospheric cause, absolutely independent of the operating conditions of the electricity system. The limitations of wind technology in operation at low frequency, if accepted in the requirements. The current dimensions of the primary reserve (63 MW) are based on the UCTE reference incident. This reference incident, 3,000 MW in the interconnected system, still considers generation failures as independent events; nevertheless, situations such as storm Klaus proves that in the interconnected system generation failure situations with a common cause can occur in a very extensive area. The same considerations can be applied regarding the current dimensions of the secondary regulation maximum band, 600 MW, based on the UCTE criteria and the conventional behavior of the system, and regarding the tertiary regulation needs based on the failure of the greatest existing unit, but in no case do they take into account a “wind power reference incident”. To determine the dimensions of the short term reserves

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Consider the possibility of increasing the secondary band. When analyzing the behavior of the case in Spain operating conditions were detected in which the current contracted secondary band runs out.[21-34] Tertiary reserve: this is the limiting element for the installed wind power, if we wish to deal with the current availability. In the case considering the reference incident for wind power failure as 70% of the installed power, this would result in a limitation of around 1,100 MW of installed wind power. Consider the possibility of using an operation instrument similar to the deviation management mechanism in the case in Spain, in such a way you can increase the limit marked by the current tertiary availability. This may only make sense if there are combined cycles or peak load power plants, its use would be limited to certain situations and it would make the functioning of the markets in Romania more complex.[21-34]

References: [1] NERC, Accommodating High Levels of Variable Generation, April 2009. [2] “Impacts of large amounts of wind power on design and operation of power systems”. IEA Wind Task 25. EWEC session 2009. [3] EWEA, Wind Energy: The Facts [4] ABB. Wind Farm Integration in British Columbia, Stage 3. Operational Impact, Prepared for the British Columbia Transmission Corporation. March 2005. [5] Impacts of large amounts of wind power on design and operation of power systems, results of IEA collaboration. IEA Wind Task 25. EWEC session 2009. [6] Institut für Solare Energieversorgungstechnik Kassel, Germany (ISET), The Influence of Modelling Accuracy on the Determination of Wind Power Capacity Effects, EWEC session 2006. [7] J. Kennedy. Queen's University, Secure System Scheduling with High Wind Penetrations, Belfast. Power & Energy Research Institute. EWEC session 2009. [8] Allan Mullane, Mark O’Malley, The inertial response of Induction-Machine-Based Wind Turbines, IEEE Transactions on Power Systems, vol.20 no.3, August 2005. [9] J. Machowski, J.W.Bialek, J.R. Bumby. Ed. Wiley, Power Systems Dynamics. Stability and Control, second edition. 2008.

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[10] P.M. Anderson, A.A. Fouad, Power System Control and Stability, IEEE Press, Ed.Wiley. 2003. [11] P. Kundur, Power System Stability and Control, Ed. McGraw-Hill, 1994. [12] GE Energy, Wind Inertia Control, GE brochure 17210 (02/09) [13] GAMESA, WINDFACT®, a solution to adapt existing wind farms to new network requirements, Presentation to the Asociación Eólica de España, January 2008. [14] Steven W. Saylors VESTAS, Meeting North America Network Codes, P.E.North East Region Systems Operators Wind Integration Seminar. February 2008. [15] ENERCON, Wind Turbines. Network Integration and Wind Farm Management, Brochure 04/2008. [16] Transelectrica, Procedura Operationala. Stabilirea Puterii Maxime Instalabile În Centralele Eoliene Din Punct De Vedere Al Sigurantei Sen. Code: Tel 07.38. Revizie: 0. November 2008. [17] Technical result of the energy sector in Romania, 2007 [18] Transelectrica, The cover of the daily load curve, 2009. [19] Transelectrica, GEN SHIFT RO si hydro scenarios, 2009 [20] Transelectrica, Generators.xls, 2009 [21] Nuclear Energy Forum. Generation mix in the Spanish electrical system in the 2030 horizon. November 2007. Document prepared by Lysys Real. www.foronuclear.org [22] Wind energy integration in the Spanish electrical system – EWEC Session 2009. [23] Wind energy development in Spain. Presentation to the MIT Energy Club. April 2009 [24] Operating Procedures for the Spanish Peninsular Electricity System. [25] P.O. 1.5 Establishing of the reserve for frequency-power regulation. Resolution of 21/7/06, BOE 21/07/06 [26] P.O. 3.1 Programming of the generation. Resolution of 28/5/09, BOE 24/05/06. [27] P.O. 3.2 Resolution of technical restrictions. Resolution of 28/5/09, BOE 24/05/06. [28] P.O. 3.3 Management of generationconsumption deviations. Resolution of 28/5/09, BOE 24/05/06. [29] P.O. 3.7 Programming of the generation of non-manageable renewable origin.Resolution of 28/5/09, BOE 24/05/06.

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[30] P.O. 7.1 Primary regulation ancillary service. Resolution of 18/7/98, BOE 24/08/06. [31] P.O. 7.2 Secondary regulation ancillary service. Resolution of 28/5/09, BOE 24/05/06. [32] P.O. 7.3 Tertiary regulation ancillary service. Resolution of 28/5/09, BOE 24/05/06. [33] P.O. 7.4 Voltage control ancillary service of the transmission network. Resolution of 18/3/00, BOE 24/03/06. Correction of errors in BOE /6/2000. [34] P.O. 12.3 Response procedures for the wind power installations in case of voltage dips. Resolution of 24/10/06, BOE 24/10/06.

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