GCC Interconnection Grid: Operational Studies for the GCC Interconnection with United Arab Emirates (UAE) N. AL-SHAHRANI GCCIA Saudi Arabia

Transcription

1 21, rue d Artois, F PARIS C4-107 CIGRE 2012 http : // GCC Interconnection Grid: Operational Studies for the GCC Interconnection with United Arab Emirates (UAE) A. AL-EBRAHIM GCCIA Bahrain K. KAROUI TRACTEBEL ENGINEERING Belgium N. AL-SHAHRANI GCCIA Saudi Arabia D. ZENNER ELIA SYSTEM OPERATOR Belgium M. AL-SHAIKH GCCIA Bahrain P. MICHAL RTE France SUMMARY The Arab Gulf Cooperation Council (GCC) countries namely the United Arab Emirates, Bahrain, Saudi Arabia, Oman, Qatar, and Kuwait have embraced changes to their power sectors with more private sectors participation as a result of increasing demands for power due to rapid population, commercial and industrial growth in their respective countries. Realizing the need for more reliable GCC power grids with power exchange possibilities, the Governments of the GCC countries have established the GCC Interconnection Authority to construct and operate a 400 kv interconnection backbone grid between the six Member States (MS). The GCC Interconnection network phase 1 was completed and successfully commissioned during the first quarter of the year Phase 1 network consists of seven 400 kv substations interconnecting the independent Member States Power Systems (MSPS): Kuwait, Saudi Arabia, Bahrain and Qatar through a 900 km 400 kv overhead lines and a 51 km 400 KV submarine and land cables. This GCC Interconnection phase I combines long distance high voltage overhead lines, high voltage cables and a HVDC back-to-back substation. The HVDC connects the 50 Hz interconnected networks of the power systems in Kuwait, Bahrain, Qatar, UAE and Oman with the 60 Hz system in Saudi Arabia. The GCC Interconnection network phase 3 successfully completed when UAE 400 kv network was connected to the GCC Interconnection network Phase 1 through double circuits 400 kv overhead lines, and synchronised for the first time with Phase I network on April 2011 and Oman grid was connected to UAE grid through double circuits 220 kv overhead lines on October In order to prepare for the safe, secure and stable operation of the combined GCC interconnection including UAE and Oman, a number of detailed operational studies were performed including system studies, electromagnetic transients, protection studies, frequency control studies, and more. The paper presents the results of these operational studies and the approach the operations issues arising from the results of the studies were addressed. KEYWORDS Large system, interconnection, stability, primary frequency control, maximum transfer capability, simulation. 1

2 INTRODUCTION The electrical interconnection process between the GCC countries power systems is a three phase process [1]: - The Phase I is related to the North Grid of the GCC power system and interconnects four Member States (MS) namely Kuwait, Saudi Arabia, Bahrain and Qatar. It is in operation since the first quarter of This phase comprise about 900 km double circuits 400 kv AC interconnection of Bahrain, Kuwait and Qatar and a 1800 MW HVDC back to back interconnector with the Eastern part of Saudi Arabia 60 Hz power system [2]. - The Phase II involves the internal interconnection and enforcement of the South Grids (UAE and Oman) to form UAE national grid and Oman northern grid which was achieved in parallel to Phase-I. The UAE electricity system is already interconnecting the separate power grids of its seven emirates to form the Emirates National Grid (ENG). Abu Dhabi is connected to Dubai, Sharjah and the other emirates through a 400 kv line. GCCIA is not directly involved in the execution of Phase II. - The Phase III is related to the interconnection between the North and the South GCC regional grids and involves the connection of UAE (Abu Dhabi) grid to Phase I, and the connection of the UAE and Oman electricity systems through 220 kv lines. From the operational studies perspective, the interconnection of the power system of Oman is performed through the double circuit 220 kv line connecting the substation of Al Foha in UAE to the substation of Mahadha in Oman. From the perspective of a 400 kv interconnection between Oman and the UAE, the 220kV interconnection operation can be considered as a conservative assumption. The Phase III has been completed in 2011 and consists of a double-circuit 400 kv corridor from Salwa (Saudi Arabia) to Silaa (UAE-AbuDhabi) then to Shuwaihat (UAE). It is successfully in operation since July Schematic and geographical views of the GCC power system are presented in Figure 1 and 2. It indicates a structure composed of rather lumped centres of consumption and generation interconnected by long 400 kv corridors between the various MS. Unlike the other MS, the power grid of Oman would be connected via a 220 kv links through the UAE network. Figure 1 : Geographical structure of the GCCIA system 2

3 Figure 2: Topological structure of the GCCIA system Prior to the Phase III interconnected operation, a number of operational studies have been performed not only to ensure the successful synchronization and operation, but also to identify stable and reliable operating regimes for the GCC interconnected system. They are related to the following aspects: short circuit analysis, maximum power transfer limits analysis, transient and small signal stability analyses, primary frequency control, adequacy of defence plans and EMTP switching simulations to assess the capability of the new equipments. GCC INTERCONNECTED SYSTEM The GCC interconnection is composed of seven 400 kv substations connecting five MS through approximately 900 km 400 kv OHL backbone connecting the substations of Al-Zour (Kuwait) in the North to the substation of Silaa (UAE) in the South. It consists of a double circuit line rated at 1900 MVA. Bahrain is connected to the 400 kv back bone through two submarine cables rated each at 715 MVA. Kuwait, Bahrain and Qatar interconnect to the GCCIA system through respectively (3x650 MVA, 3x325 MVA and 3x400 MVA transformers). Saudi Arabia is connected through a back-to-back HVDC converters rated at 3x600 MW at the 400 kv substation of Al-Fadhili. The HVDC station, in addition to being designed for economic power exchanges, has a novel feature that enables Dynamic Reserve Power Sharing (DRPS) between the 60 Hz and 50 Hz systems, and has been to date activated on several occasions following severe active power unbalances for mutual support between the 50 Hz and the 60 Hz systems. The system is operated according to an Interconnection Transmission Code (ITC) that requires among others, the N-1 security criterion for the largest credible contingency. The net transfer capacity (NTC) is obtained by subtracting to the total transfer capacity (TTC) the transfer reliability margin (TRM). The latter accounts for unintentional deviations such as physical flows due to power frequency control, unexpected unbalances between MS system operators and inaccuracies deriving from collected data and measurements. Additionally, the system is equipped with a set of nineteen 125 and 300 MVAr line, cable and substation connected shunt reactors. The substation reactors are operated to balance the MVAr exchanges and control voltages at the interface between GCCIA and the MS power systems. 3

4 Total peak load of the GCC countries power system is estimated at 92.5 GW when minimum load is estimated at 35.4 GW. This high peak load vs. minimum load ratio is due to the high proportion of air conditioning load during hot summer temperatures. POWER SYSTEM MODEL AND CONSIDERED OPERATING CONDITIONS Power system studies were performed using a detailed model of the interconnected MS power systems developed with the assistance and cooperation of the Member States. It represents a 650 generator system for the 50 Hz system while the units of KSA Eastern operating region (60 Hz) are also represented in their real identity and where the three other operating regions (Western, Central and Southern) are represented by equivalent models. The system model accounts not only for the various security systems mainly the under frequency load shedding system but also for the HVDC back-toback station and its Dynamic Reserve Power Sharing (DRPS) function. In addition, the peak load model includes a high proportion of rotating load in the load mix. This translates into an equivalent induction motor at each load bus connected downstream an equivalent distribution transformer and medium voltage feeder. Peak load analyses are performed on three steady state operating conditions: i/ no power exchanges between the MS, ii/ maximum power transfer stream from North to South and iii/ maximum power transfer stream from South to North. The later two operating conditions are considered as most severe normal conditions since the angle difference between Kuwait and Oman is maximized and reaches 52. Minimum load analysis is performed assuming no power exchanges between MS. This is representative of the large volume of tertiary reserves available during winter period in each MS. For all considered cases, the spinning reserve is adjusted to the minimum required as per the interconnector code. This is a conservative assumption during winter period as desalination constraints provide large primary reserve margins. IMPACT OF THE INTERCONNECTOR ON THE SHORT CIRCUIT LEVELS Single and three phase faults levels have been determined according to IEC standard before and after Phase III interconnection assuming 50 ms contact parting time. Obtained results indicate that the 400 kv GCCIA substation breakers have the capability to interrupt successfully symmetric and asymmetric 1-ph and 3-ph faults. Fault level at the 400 kv substations, Silaa remains significantly below 30 ka for a breaker capability of 63 ka. SMALL SIGNAL STABILITY After Phase III interconnection, the 50 Hz part of the GCC system is characterized by a set of power systems connected together through relatively long AC lines leading to a longitudinal system structure. Although the GT, ST and CCGT generation mix of all MS is not prone to low damping inter-area oscillation, the interconnection of North and South parts will change the shape of the existing oscillation modes and new inter-area modes will be experienced. Phase I interconnection analysis had already highlighted the need to improve inter-area modes between Kuwait, Bahrain and Qatar. Installation and re-tuning of dedicated PSS are ongoing in Kuwait and Qatar large power plants generators. The analysis focuses on the modes comprised between 0.05 and 1 Hz i.e. the modes related to coherent groups of units. The modes are considered as insufficiently damped when the damping factor falls below 5% in all credible contingency conditions. After linearization of the differential-algebraic set of non linear equations, the inter-area modes and their damping are calculated on base of an Arnoldi method. In order to secure a conservative assessment of the damping, the following situations have 4

5 been considered in peak and off-peak load: i/ base case without contingency i.e. N case; ii/ N-1 contingency cases with for each considered case, one circuit out of service; iii/ N-2 situation where Bahrain and Qatar are absent increasing the electrical distance between the North and the South parts of the GCC system; iv/ simultaneous N-1 contingencies on all interconnection corridors. All new inter-area modes display a damping rate higher than 5% with natural frequencies comprised between 0.19 and 0.6 Hz. The lowest damping factor (7.5 %) is encountered in N-2 contingency situation when Qatar is not connected. The damping of the existing GCC Phase I mode involving Kuwait, Bahrain and Qatar increases to 6.75% due to the introduction of the PSS in Qatar and Kuwait. Figure 3 below illustrates the inter-area oscillation modes on the GCCIA system. 2 groups mode: 15% <ξ< 37% and 0.19 Hz <f< 0.31 Hz 4 groups mode: 7.5% <ξ< 15% and 0.40 Hz <f< 0.47 Hz BA QA UAE OM BA QA UAE OM BA QA UAE OM BA QA UAE OM 3 groups mode: 6.7% <ξ< 14% and 0.39 Hz <f< 0.50 Hz 3 groups mode: 13% <ξ< 20% and 0.34 Hz <f< 0.42 Hz BA QA BA QA UAE OM BA QA BA QA UAE OM Figure 3 : Inter-area oscillation modes on the GCCIA system As these damping levels are model based conclusions, GCCIA is monitoring the effective damping achieved on the GCCIA various corridors during the early phase on the interconnected operation. The longitudinal and multi power flow pattern makes the GCCIA system a good candidate for a Phase Measurement Unit (PMU) based wide area inter-area oscillations monitoring system. Optimal locations for dynamic observability are the substations of the GCCIA system and the large power plants connecting substations in the MS grids. TRANSIENT STABILITY Transient stability has been assessed to verify the ability of the system to withstand normally cleared 1-ph and 3-ph cleared in base (80 ms) and back-up (325 ms) time. As loss of synchronism following faults inside the MS is prevented by the MS internal protection schemes, the main focus of the assessment is the risk of cross border loss of stability. Obtained results are critical inputs for the location and the settings of the out of step relays along the GCCIA 400 kv corridors. In addition, following severe faults, the air conditioning load inside the MS impacts the voltage stability of the system. However, its impact on the GCCIA interconnection is limited by the presence of low voltage relays located the GCCIA substations connecting the MS. Angular stability following 3-ph faults cleared in base time is verified with 100% impedance load on the peak load high power transfer scenarios. Following 3-ph faults cleared in back-up time due to breaker failure, losses of synchronism appear for faults located close to Al-Zour, Ghunan, Al Jasra, Salwa and Shuweihat. This conclusion is confirmed by a set of critical clearing times found lower than 325 ms and justifies the installation of out of step relays at suitable locations of the GCCIA system. 5

6 INTERCONNECTION TRANSFER LIMITS Together with the thermal limits, the knowledge of the maximum transfer limits is a key input of the total transfer capacities and therefore the net transfer capacity assessment. Their comparison with the thermal limits of the corridors defines if a corridor security limit is thermally or stability driven. Maximum power transfer capacity is defined as the maximum power flow between two MS of the system. For each pair of MS, two values are determined corresponding to the maximum transfer limit in both directions. They are achieved in peak and minimum load in N and N-1 contingency situations corresponding to the loss of the major elements of the GCCIA system (i.e. 400 kv circuit and MS- GCCIA transformer) p.u. Kuwait KSA Bahrain Qatar UAE Kuwait KSA Bahrain Qatar UAE Table 1 : Maximum transfer capacity between MS at peak load (N situation) in MW [uae2k] UAE to Kuwait Transfer [ua2k] VOLTAGE AT NODE : SALWA1 Unit : p.u. [ua2k] VOLTAGE AT NODE : GHUNAN1 Unit : p.u. [ua2k] VOLTAGE AT NODE : FADHILI1 Unit : p.u. [ua2k] VOLTAGE AT NODE : ALZOUR1 Unit : p.u. Figure 4 : Maximum power transfer in MW vs. voltage in p.u. between UAE and Kuwait in normal conditions. Kuwait KSA Bahrain Qatar UAE Kuwait KSA Bahrain Qatar UAE Table 2 : Maximum transfer capacity between MS at peak load (N-1 situation) in MW Figure 4 presents the 1600 MW maximum power transfer between UAE and Kuwait in normal conditions. Tables 1 and 2 present the obtained max transfer capacity results matrices in N and N-1 contingency situations. Effective transfer capacities are derived from the max transfer capacity by subtracting a 20% margin. PRIMARY FREQUENCY CONTROL The interconnection of AC systems requires the definition of common rules for primary reserves and the determination of the expected contribution of each system to the primary frequency control. Their main impact is the determination of the transfer reliability margin. Contribution to the primary frequency control is regulated by the interconnector code. It stipulates that the secured incident size must correspond to the largest single credible incident (480 MW) following the loss of a unit in UAE) increased by a margin of 10%. The reserve allocated to each unit shall not exceed 5% of its size. The sharing of the spinning reserve volume between the MS is in accordance to their generation size in the total synchronous system. Minimum contribution in % to the total spinning reserve is presented in Table 3: Member State C i (%) Spinning Reserve (MW) Bahrain Oman Qatar Abu Dhabi Kuwait Total Table 3 : Spinning reserve allocation between MS Figure 5 : Transfer margin on GCCIA 400 kv corridors for primary frequency control 6

7 The contribution of the primary frequency control to the transfer reliability margin is required to permit the secure power flows on the various GCCIA interconnectors induced by the primary frequency control. Those contributions vary with the corridor location and correspond to the largest active power flow variation induced by the loss of the largest unit in each member state and the subsequent primary frequency control activation. Margins required for a largest loss located in Qatar are presented in Figure 5. The larger the system total size, the lower frequency deviation the system will experience following the largest generation loss. This requires to monitor and to take into account the governor voluntary dead-bands but also, above a given size, the impact of the frequency insensitivity ranges to better predict the response of the MS following a generation trip. ADEQUACY OF DEFENCE ACTIONS Defence actions are of three types: - Under frequency load shedding (UFLS) and, below a given frequency level, disconnection of importing MS; - MS disconnection below a given voltage level at the connecting substation; - Out of step relay to avoid the spread of out of step operating conditions. The Under Frequency Load Shedding adequacy has been harmonized to limit transient power flows due to discrepancies between the various MS UFLS subsequent to their activation. Taking into account the UFLS harmonization done for phase-1 countries and the large volumes related to each load shedding stage (approximately 2400 MW corresponding to 5% of the 50 Hz system total interconnected system peak load), Oman UFLS settings are adjusted to secure the frequency stability of an islanded system by adjusting the first stage set at 49.3 Hz instead than 49.5 Hz and increase the UFLS total from 35% to a value above 40% of the total load and UAE UFLS harmonization has been achieved by splitting of the previous first UFLS stage into two distinct stages (49.3 Hz, 5%) and (49.2 Hz, 5%). Minimum Voltage Relay: To mitigate the extension of delayed voltage recovery induced by a lack of dynamic reactive power reserves or under voltage load shedding in one MS and the consequent risk of voltage collapse, a low voltage back up protection prevents that low voltages at the point of common coupling impact the integrity of the bulk GCCIA interconnection. It is activated if the voltage remains below the range p.u. during several seconds. Out Of Step Relays presence is necessary to mitigate the detrimental impact of out of step operating conditions between the various parts of the GCC system. Out of step relays (OOS) are located on the various corridors potentially subject to a loss of synchronism. Their tuning is performed according the following methodology: - Definition of a target trip matrix on base of the transient stability simulation results. The location and activation requirements are based on the requirement to keep coherent groups of generators; - Assessment of the OOS relays ability to detect out of step operating conditions. An achieved trip matrix is therefore defined and compared to the target trip matrix to confirm the adequacy of the relay locations. - Relay operation assessment on base of the simulated X/R trajectories and the detailed Areva MiCOM P754x logic. When necessary, zone 5 and zone 6 parameters and bandwidth crossing time are adapted. - The four OOS relays settings are validated on the simulation of a large number of fault locations and initial operating conditions (74). Simulation results indicate a success rate of 92% for faults cleared in back-up time following a breaker failure. It is observed that the out of step is not activated following a fault clearing in base time reducing further the risk of maloperation. The behaviour of the GCCIA system has been assessed on the simulation of large disturbances especially the stability of GCCIA various parts following the simultaneous loss of the two circuits 7

8 composing a transmission corridor. This leads to the split in two parts of the system and the activation of the UFLS in case of large North-to-South or South-to-North power exchange. The response of the system includes the activation of the UFLS and the HVDC back-to-back dynamic reserve power sharing (DRPS) logic. The synthesis of the simulated loss of corridor results is presented in Table 4. Table 4: Ability of the GCC subsystems to recover following a N-2 contingencies leading to a GCC system split Achieved results highlighted the need to extend the transfer reliability margin to the power flow transients related to the first UFLS stage and to improve the HVDC back-to-back interconnector response and underlying DRPS logic [4] to better cope with sudden large export rejection (i.e. generation excess and over frequency transients) but also a following large generation deficit. An ongoing project aims at improving the HVDC interconnector DRPS logic. PROTECTION STUDIES The protection studies mainly focused on the new interconnections and substations put in place to link the North and the South GCC regional girds (Part III). Nevertheless a thorough analysis of the protections of the adjacent interconnections and substations was performed to determine the consistency with the new used protections. The studies focused on three domains: control of the philosophy used to protect the installations as well as its correct translation into the used block diagrams, cross-check of the protection settings via calculations and, at last, simulations via PSS SINCAL to have a full selectivity check on the interaction of all used protections (Figure 6). Different types of simulations were conducted where faults (three phase and single phase faults) were simulated at the beginning (10%), middle (50%) and end (90%) of every interconnection and on bus bars of every substation (and this all for peak and off-peak conditions) (Table 5). For each simulation, the state of the protection was analyzed (trip, pick-up, no start) as well as the tripping zone/time and the measured impedance. General conclusion is a correct behaviour of all used protections and proposed settings and a guaranteed selectivity for types of simulated faults. 8

9 Figure 6: Simulated grid Table 5: Response of fault clearance by backup distance protections for faults on bus bars (1ph/3ph, peak/off-peak). The major recommendations of the studies were optimizations on the auto reclose program as well as on the philosophy of the breaker failure protection. The breaker failure protection scheme was reviewed in order to lower the fault clearance time. The recommendation consisted in a second trip command issued by the main protections of the interconnections and a simplification towards a one stage breaker failure protection scheme and hence a gain in fault clearance time. CONTRIBUTION TO PRIMARY FREQUENCY RESPONSE BY PHASE I MEMBER STATES In an interconnected system, the spinning reserve is shared among the members. The spinning reserve includes primary and secondary reserves and is given by the sum of the values of power between the set-power at the reference frequency, and the limiter position of each power plant. GCCIA has taken the following principles for the spinning reserve [3]: SALWA SILAA 3peak 3offpeak 1peak 1offpeak 3peak 3offpeak 1peak 1offpeak Dist Salwa L5 OK OK OK OK OK OK OK OK Dist Salwa L6 OK OK OK OK OK OK OK OK Dist Salwa L7 OK OK OK OK OK OK OK OK Dist Salwa L8 OK OK OK OK OK OK OK OK Dist Salwa L11 OK OK OK OK OK OK OK OK Dist Salwa L12 OK OK OK OK OK OK OK OK Dist Silaa L11 OK OK OK OK OK OK OK OK Dist Silaa L12 OK OK OK OK OK OK OK OK Dist Silaa L13 OK OK OK OK OK OK OK OK Dist Silaa L14 OK OK OK OK OK OK OK OK Dist Ghuna L5 OK OK OK OK REM REM REM REM Dist Ghuna L6 OK OK OK OK REM REM REM REM Dist Doha S L7 OK OK OK OK REM REM REM REM Dist Doha S L8 OK OK OK OK REM REM REM REM Dist Schuwe L13 OK OK OK OK OK OK OK OK Dist Schuwe L14 OK OK OK OK OK OK OK OK The total primary reserve must cover the reference incident. As regards the duties towards the partners, the reference incident is taken equal to the largest unit installed within the interconnected system. Otherwise, each partner may choose a more restricting rule, (for instance simultaneously 2 power plants in Kuwait). The primary reserve is calculated in such a way that in the case of the tripping of the largest generating unit, after the delivery of the primary reserve, the final frequency deviation should be at maximum equal to 200 mhz. The available secondary reserve is the difference between the spinning reserve and the primary reserve. It must be noticed that in addition, this reserve is distorted by the change of the set power. The primary and the secondary reserves are allocated amongst the members in proportion to their largest installed generating unit. 9

10 For the reference incident, the frequency must not drop transiently below Hz on the 50 Hz side. The HVDC station, in DRPS mode delivers 240 MW, 0.5 s after detection of the disturbance, if the three following conditions are verified: The voltage variation rate dv/dt is greater than preset value. currently, it is set at 0; The frequency variation rate df/dt is greater than preset value. Currently, it is set at 0.05 Hz/s; The calculated contribution of the HVDC power station, based on a theoretical frequency gain, is greater than 240 MW. Once the DRPS of the HVDC power station is de-blocked, the initial contribution of the HVDC power station is then reduced or increased in accordance with the calculation done with the frequency controller gain. If requested, the second pole is de-blocked 4 s later. The largest generating unit connected to the GCC system during the study amounts to 664 MW and this unit is connected to the Saudi Arabia 60 Hz system. The tripping of that generating unit might be the reference incident. However, in case of tripping of the largest unit in Saudi Arabia (664 MW), the DRPS may not be activated because the thresholds may not be reached and the spinning reserve in that case should not change for Saudi Arabia. On the 50 Hz side, the three systems are interconnected: i.e. Kuwait, Bahrain and Qatar. Because of the results of the previous reference incident (loss of 664 MW in Saudi Arabia has no consequence on the 50 Hz side), the largest generating unit on the 50 Hz side is considered as the reference. Even on 50 Hz side, of the HVDC back-to-back power station, is not always activated for the same amount of generation loss. It depends on the load level, on the location of the tripped generating unit and on the unit commitment. Thus for safety reason, the potential contribution of the HVDC back-to-back power station is not taken into consideration. This assumption avoids underestimating the primary reserve on the 50 Hz side, which can drive to load shedding, if the HVDC back-to-back power station is not activated. If the back-to-back is activated, the 60 Hz system contributes to the incident, thus the frequency deviation should be smaller. At the time of conducting the studies, the largest generating unit on the 50 Hz side is a combined cycle in Qatar for 375 MW (one Gas Turbine and part of the associated steam turbine). Consequently, this incident is simulated for peak and off-peak load. The results of these simulations will give the necessary amount of primary reserve, in order to comply with GCCIA rules and determine the sharing of primary and secondary reserves between each GCCIA member. The two values for the minimum primary reserve, for both peak and off-peak periods are very close: 300 MW and 272 MW, but the reference incidents are quite different: in one hand the loss of 375 MW and in other hand the loss of 283 MW. But the most important is the contributions of each country are different, because the shares are based on the largest running generating units: Kuwait peak contribution: 91 MW and 150 MW for off-peak. Bahrain peak contribution 93 MW and 44 MW for off-peak. Qatar peak contribution 117 MW and 78 MW for off-peak. For operations it would be very difficult for GCCIA to monitor the primary reserve and also to determine, which set of primary reserve is requested. Therefore it is highly recommended to calculate the contribution of each system on the base of the total active power generated in each system. Obviously with the calculations based on the largest generating unit, the benefits of the reserve reduction are equally shared among the participants, but for the reliability of the interconnected system it is not recommended. 10

11 Regarding the behaviour of the back-to-back power station, for the two load levels, peak and off-peak, the thresholds are not activated in case of the tripping of the generating unit in Ras Laffan B in Qatar, with of power of 375 MW. But for off-peak and for a smaller amount of generation tripped in Kuwait, only 283 MW, the back-to-back power station is activated. Therefore for the estimation of the primary reserve the contribution of the back-to back power station cannot be taken into account, because it highly depends on the location of the tripped generating unit and not on the amount of the generation loss. The DRPS is activated only to stabilze the system in case for critical emergency but the HVDC is available for commercial exchange through the Economic Transfer more. For Saudi Arabia, the amount of primary reserve is not reduced yet with the interconnection, however, with enhancement of the HVDC control system through a new triggering based on change in frequency ( F) that is intended to be added separately in addition to the already existing triggering; df/dt and dv/dt triggering criteria, DRPS will be activated for losing the largest generator on the combined system as well as major system disturbances. CONCLUSIONS The GCC interconnection is becoming a key element of the secure and reliable power supply to the GCC countries. These high security and reliability requirements are mandatory conditions to further optimize the GCC power system allowing power exchanges between the member states. The longitudinal structure of the GCCIA Interconnection due to long distances of the transmission corridors requires a careful assessment of the total transfer capacities and the transmission reliability margins. The HVDC back-to-back interconnector is an important actuator to allow the optimization of the mutual support between the 50 and 60 Hz synchronous system during normal and emergency conditions. The fast expansion of the member states power system and the opportunities offered by the GCCIA system pose a number of operational new challenges: - the data management and modelling coordination tasks between GCCIA and the member states to master a continental size power system model especially when including the 60 Hz KSA interconnection; - the static and dynamic observability of the whole interconnection that is mainly concentrated in the MS especially the contemplated roles of a PMU based wide area monitoring system (WAMS) and in the longer term protection system (WAPS); - the progressive migration from the actual interconnector transmission code focused on the GCCIA system coupled with an harmonization of the key cross border features to a unified technical code framework applicable to the whole GCC system. Together with the member states, the GCCIA is a central and a key stakeholder to head these challenges. BIBLIOGRAPHY [1] H.K. Al Asaad, A.A. Ebrahim The GCC power grid: Benefits & Beyond Powergen 2008 Conf. [2] A. A. Al-Ebrahim, N. Al-Shahrani, G. Stalens, J. Dubois, J. Warichet Preparation GCC Interconnection Operations through Operational Studies and Analysis GCC CIGRE 2009 Conf. [3] N. Al-Shahrani, R. Lopez, N. Vidal, G. Nauton GCCIA System Frequency Control Philosophy GCC CIGRE 2009 Conf. [4] A. A. Al-Ebrahim, N. Al-Shahrani The Dynamic Reserve Power Sharing Mode of GCC Interconnection HVDC Link: Novel Design and Features GCC CIGRE 2010 Conf. 11