Review of Normal and Infrequent In-feed Loss Risks in the Transmission System of Oman

Helwan University From the SelectedWorks of Omar H. Abdalla November 10, 2014 Review of Normal and Infrequent In-feed Loss Risks in the Transmission System of Oman Omar H. Abdalla, Helwan University Adil Al-Busaidi Hilal Al-Hadi Hisham A. Al-Riyami Ahmed Al-Nadabi Available at: https://works.bepress.com/omar/21/

Review of Normal and Infrequent Infeed Loss Risks Omar H. Abdalla*, Adil Al-Busaidi, Hilal Al-Hadi, Hisham Al-Riyami, and Ahmed Al-Nadabi Oman Electricity Transmission Company (Sultanate of Oman) Summary: The paper presents technical studies performed to review the values of the Normal Infeed Loss Risk (NILR) and Infrequent Infeed Loss Risk (IILR) in the Transmission System Security Standard (TSSS). The objective is to facilitate the connection of the largest power station in Oman, which is Sur 2000 MW IPP, to the Main Interconnected Transmission System (MITS), while complying with the requirements of the TSSS. The full output of 2000 MW of Sur power plant is expected to available in 2015; therefore the MITS model of 2015 is used in the studies using the DIgSILENT professional software. The model includes static and dynamic representations of each generating unit with its synchronous generator, turbine, speed governor, exciter, and automatic voltage regulator; in addition to representation of the network transmission lines, transformers and loads. System studies have been performed to assess the dynamic performance of the MITS when it is subjected to various levels of loss of power infeed at Sur power plant. The objective is to make sure that both voltage and frequency are within the allowable limits, stability is maintained and no overloading before and after the loss of power infeed. The studies presented in this paper are corresponding to the following expected demand levels in 2015: Minimum demand of 1760 MW Off-peak demand of 3000 MW Peak demand of 5560 MW The results have shown that the following reviewed values of the normal and infrequent loss of infeed risks should be used to facilitate the connection of the 2000 MW Sur IPP: The NILR is 500 MW at system demands above 3000 MW falling to 390 MW at system demands below 2000 MW. The IILR is 780 MW at system demands above 3000 MW falling to 500 MW at system demands below 2000 MW. Keywords: Normal Infeed Loss Risk, Infrequent Infeed Loss Risk, Transmission System Security Standard. 1. INTRODUCTION There has been a considerable electricity demand in Oman during recent years associated with the high development in various activities including industrial, tourism, commercial and residential loads. The average annual load growth rate reaches about 9.5% [1]. To cope with this high rate growth demand, new power stations have to be installed and connected to the power network. Among these power stations; is Sur 2000 MW IPP which will be fully commissioned in 2015. The addition of such large power station, with large generating units, to the MITS requires reviewing the values of both normal and infrequent infeed loss risks which are defined in the TSSS [2]: The normal infeed loss risk is defined as the level of loss of power infeed risk which is covered over long periods operationally by frequency response to avoid a deviation of system frequency by more than 0.5Hz. The infrequent infeed loss risk is defined as that level of loss of power infeed risk which is covered over long periods operationally by frequency response to avoid a deviation of system frequency outside the range 49.5Hz to 50.5Hz for more than 60 seconds. The loss of power infeed is defined as the output of a generation unit or a group of generation units or the import from external systems disconnected from the system by a secured event, less the demand disconnected from the system by the same secured event. For the purpose of the operational criteria, the loss of power infeed includes the output of a single generation unit, CCGT module, or boiler lost as a result of an event. Dynamic simulation studies have been performed based on the power system models of year 2015 by using DIgSILENT software [3]. The studies include * Prof. Omar H. Abdalla was with the Oman Electricity Transmission Company. Currently he is with the University of Helwan, Egypt, E-Mail: ohabdalla@ieee.org

peak, off-peak and minimum demand loading conditions. Updated values of both NILR and IILR have been obtained and amended to the TSSS. The updated values have been already approved by the Authority for Electricity Regulation (AER) [4], and being in use in Oman. Section 2 presents the MITS description and modelling. Section 3 presents description of Sur IPP. Section 4 presents extracts from the TSSS concerning the limits of power infeed loss risks and generation connection requirements. Section 5 presents the TSSS requirements for the Sur power plant. Section 6 concerns with the NILR, and Section 7 concerns with the IILR. Section 8 presents system studies, and Section 9 presents simulation results. Finally, Section 10 summaries the main conclusions. 2 SYSTEM DESCRIPTION AND MODELLING 2.1 System Description The main interconnected transmission system (MITS) extends across the whole of northern Oman and interconnects bulk consumers and generators of electricity located in the Governorates of Muscat Batinah South, Batinah North, Bureimi, Dhahirah, Dakhiliyah, Sharquiya North and Sharquiyah South [5]. Figure 1 shows a geo-schematic diagram of the expected configuration of the MITS of Oman in 2015. Currently, the MITS model is composed of three voltage levels: 220 kv, 132k V and 33 kv. In 2015, the 400kV will be in operation for the first time in Oman. The transmission lines are fitted with double circuit to satisfy the (N-1) criterion of the TSSS. In general, the substations of 220/132 kv and 132/33 kv present an arrangement of two transformers in parallel. The 400/220 kv substations will consist of two or more transformers to allow bulk power transmission of new large power plants. The 33 kv network is operated by the licensed electricity distribution companies, e.g. Muscat, Majan and Mazoon. Only the 33 kv primary substations pertaining to the 132/33 kv transformation are represented in the model. The downstream loads are represented by an equivalent load model. The electric power transmitted through the main grid, is fed, through 220/132/33 kv, 132/33 kv and 132/11 kv grid stations, to the three distribution licence holders, namely, Muscat Electricity Distribution Company, Mazoon Electricity Company and Majan Electricity Company, in addition to directly-connected large private customers. A number of large private customers are connected directly to the transmission system either at 220 kv or 132 kv. Some customers have their own generation capability on site and can exchange power with the MITS. For the studies presented here, no power exchanges are considered. Currently, Oman is interconnected with the UAE through a 220kV doublecircuit transmission line. A new 400kV interconnection is planned to be in operation in 2015 [6]. Figure 1 : Expected configuration of Oman main transmission system in 2015.

2.2 System Modeling A detailed model of the MITS has been developed [7] to simulate the steady-state and dynamic system performances using the DIgSILENT software. A brief description is given here. Each generator is represented by a dynamic model based on Park s equations. It is assumed that the rotor has one damper winding in the d-axis and two damper windings in the q-axis [8]. All the generating units are equipped with automatic voltage regulator. Most generating units in Oman are driven by gas turbines in an open cycle basis and some are driven by steam turbines. New power plants use combined cycle (gas plus steam) CCGT configuration. In the combined cycle power plants models, the governor valve of the steam part is made insensitive to frequency variations, since the frequency response is usually achieved through the speed governor of the gas turbine part. Standard IEEE models are used to represent turbines, speed governors generator exciters and automatic voltage regulators. Each open cycle gas turbine and open cycle steam turbine is equipped with a speed governing system with 4% speed droop characteristics. All these units will contribute in the recovery of the frequency when the system is subjected to loss of generation. In the combined cycle configuration, the gas turbine is equipped with a speed governor with 4% speed droop, while the steam turbine is working with fully open governor valve. In this case (CCGT) the GT contributes to frequency control while the steam turbine has a relatively very slow response beyond the simulation time and therefore considered to have constant power output. Figure 2 shows the block diagrams of the IEEE standard models used to represent the turbine and speed governor systems. Figure 3 shows the block diagrams of the IEEE standard models representing the excitation and AVR systems. These include rotating and static types. The IEEE Type AC1 model is used to represent a brushless permanent magnet generator excitation system. The IEEE Type ST1 model is used to represent the static excitation type. Transformer models include the magnetization reactance and iron loss admittance in addition to the leakage reactance and winding resistance. On-load tap changers with their automatic control facilities; and off-load tap changers are simulated in the transformer model. In Oman, the main transmission system comprises double-circuit transmission lines; most of them are overhead lines and only a few are cables. 3 SUR POWER STATION Oman Electricity Transmission Company (OETC) has received a Connection Application from Oman Power and Water Procurement Company (OPWP) requesting the connection of 2000 MW of generation capacity at Sur. The generation capacity will be developed as two phases: The 1st stage of 500 MW consists of gas turbine generating units The 2nd stage of 1500 MW consists of both gas and steam turbine generating units operating in combined cycle form (a) Gas Turbine Governor Model (GAST) (a) IEEE Type AC1 model. (b) Steam turbine governor models (IEEE SGO) Figure 2: IEEE standard models of the turbine and speed governor systems. (b) IEEE Type ST1 model. Figure 3: IEEE standard models of the exciter and automatic voltage regulator systems.

On the 6th of July 2011, OPWP and the developers signed the contract of Sur Power Station with a total contracted capacity of 2000 MW. The Sur power station will consist of three combined cycle blocks: Block A will consist of two Gas Turbines (GT), two Heat Recovery Steam Generators (HRSG) and one Steam Turbine (ST), i.e. (2+2+1) configuration Block B will be the same as Block A; (2+2+1) configuration Block C will consist of one GT, one HRSG and one ST, i.e. (1+1+1) configuration Table 1 shows the generating capacity of the generating units in each block. The rated and maximum generation capacities are: The rated generation capacity of Block A is 766.8 MW; (2x219.9 MW + 1x327 MW) The maximum generation capacity of Block A is 847.8 MW; (2x258.9 MW + 1x330 MW) The rated and maximum capacities of Block B are the same as those of Block A. The rated generation capacity of Block C is 381.6 MW; (1x219.9 MW + 1x161.7 MW) The maximum generation capacity of Block C is 422.3 MW; (1x258.9 MW + 1x163.4 MW) The total rated generation capacity of the power station is 1915.2 MW. The total maximum generation capacity of the power station is 2117.9 MW The rated and maximum outputs of the gas turbine are: The rated output is the design condition, which was specified as being 50 o C ambient air temperature, 30% relative humidity and a seawater temperature of 36 o C. At this condition, each gas turbine is rated at 219.9 MW (gross output, at generator terminals). The Maximum output relates to the same ambient temperature conditions (50 oc, 30% humidity) but with the evaporative cooler and wet compression systems turned on. These systems provide additional power output for peak dispatch. 4 EXTRACTS FROM THE TSSS [2] 4.1 Limits to Loss of Power Infeed Risks For the purpose of applying the Transmission Security Standards, the Loss of Power Infeed resulting from a Secured event shall be calculated as follows: the sum of the registered capacities of the Generation Units disconnected from the system by a Secured event; plus Generation connections shall be planned such that, starting with an Intact System, the consequences of Secured events shall be as follows: following a fault outage of any single Transmission Circuit, no Loss of Power Infeed shall occur; following the Planned Outage of any single section of Busbar, no Loss of Power Infeed shall occur; following a Fault outage of any single Generation Circuit or single section of Busbar, the Loss of Power Infeed shall not exceed the Normal Infeed Loss Risk; following the Fault outage of any single Busbar coupler circuit breaker or Busbar section circuit breaker, the Loss of Power Infeed shall not exceed the Infrequent Infeed Loss Risk; following the Fault outage of any single Transmission Circuit or single section of Busbar, during the Planned Outage of any other single Transmission Circuit or single section of Busbar, the Loss of Power Infeed shall not exceed the Infrequent Infeed Loss Risk; following the Fault outage of any single Busbar coupler circuit breaker or Busbar section circuit breaker, during the Planned Outage of any single section of Busbar, the Loss of Power Infeed shall not exceed the Infrequent Infeed Loss Risk. Block No. Generating Unit Table 1: Generation Capacities of Sur Power Station Units Rated Generation Capacity (MW) Maximum Generation Capacity (MW) Minimum Generation Capacity (MW) Block A GT-A1 219.9 258.9 128 GT-A2 219.9 258.9 128 ST-A1 327 330 98.1 Block B GT-B1 219.9 258.9 128 GT-B2 219.9 258.9 128 ST-B1 327 330 98.1 Block C GT-C1 219.9 258.9 128 ST-C1 161.7 163.4 48.5 Total 1915.2 2117.9

4.2 Normal and Infrequent Infeed Risks The definition of limits for Normal Infeed Loss Risk and also Infrequent Infeed Loss Risk are presented in Table 2. For clarity, the definition of Generation Circuit is also presented [2]. Table 2: Definitions of normal and infrequent infeed loss risks. Normal Infeed Loss Risk Infrequent Infeed Loss Risk Generation Circuit That level of Loss of Power Infeed risk which is covered over long periods operationally by frequency response to avoid a deviation of system frequency by more than 0.5Hz. That level of Loss of Power Infeed risk which is covered over long periods operationally by frequency response to avoid a deviation of system frequency outside the range 49.5Hz to 50.5Hz for more than 60 seconds. The sole electrical connection between one or more Generation Units and the Main Interconnected Transmission System, i.e. a radial circuit which if removed would disconnect the Generation Units 5 TSSS REQUIREMENTS TO THE SUR POWER STATION AND MITS CONNECTION The new power station at Sur will have a total installed maximum generation capacity of 2117.9 MW and total rated capacity of 1915.2 MW. The contracted total generation capacity is 2000 MW. The power station will have three blocks, each in a combined cycle arrangement as indicated above in Table 1. The power station comprises eight generating units, five gas turbines and three steam turbines. Each gas turbine unit has about 220 MW rated generation capacity and associated, likely similarly rated HRSG. The maximum capacity of each gas turbine unit is about 260 MW. Two steam turbine units have the same rated generation capacity of about 330 MW each. The third steam turbine unit has a rated generation capacity of about 162 MW. The use of generators of these relatively large ratings (within the context of the Oman MITS) is presumably to deliver benefit from the economies of scale that result from the use of larger rated gas and steam turbine technology. However, implicit in the use of higher rated units is the need for the MITS to be operated with an increased level of system generation reserve, both spinning and static, such that demand can be secured in the event of the planned and unplanned outage of one or more of the larger generation units. Whilst the TSSS is largely concerned with the design and operation of the MITS, the Loss of Power Infeed risk referenced above, clearly reflects assumptions about the dispatch and operation of the generation connected to the MITS. Accordingly it is therefore appropriate to review both the Normal and also Infrequent Infeed Loss Risk prior to undertaking the design of the connection arrangements for such a power station and, in the absence of such a review it may be considered either impossible to connect such a power station and its individual generators to the MITS, or alternatively that a somewhat non-sensible connection arrangements may result. 6 NORMAL INFEED LOSS RISK Based upon the indicated individual generator ratings of between about 162 MW for the smallest unit to 330 MW for the largest unit, it may be assumed that at times of peak demand on the MITS, adequate spinning reserve (up to 330 MW) will be carried on the network if the need for load shedding is to be avoided. In practice, when it is recognised that the affected generation will also likely carry a proportion of such spinning reserve and will therefore be operating somewhat below rated power, a somewhat smaller potential loss of generation will result, with a proportionate reduction in the need for spinning reserve. However, in the case of a Combined Cycle Gas Turbine/Steam Turbine plant (CCGT), the loss of a gas turbine unit will also result in some loss of energy to the HRSG unit, typically equivalent to about 50% of the gas turbine loading. As a consequence and on the basis of a typical generation (2xGT+2xHRSG+1xST) configuration then the loss of a single GT will result in a power infeed loss to the MITS between about 330 MW and 390 MW: 330MW (1xGT+50% of the GT) when operating at rated generation capacity of 220MW 390MW (1xGT+50% of the GT) when operating at maximum generation capacity of 260MW This is with an attendant need for the MITS to carry even more spinning reserve if load shedding is to be avoided in the event the sudden loss of one of the larger new generation units. On the basis of the above simplified assessment relating to the Sur power station, it is evident that the normal infeed loss risk should be increased to about 390 MW from the old assigned level of 100 MW to something in excess of the rating of the largest unit. It should be noted that the sensitivity of this Plant Loss Risk to the system demand level may not be linear, as implied by the assigned normal infeed loss

risk, and will be dependent upon assumptions relating to generation dispatch, minimum techno-economic generation unit operating levels and also spinning reserve practices at times away from system peak demand. 7 INFREQUENT PLANT LOSS RISK In the case of the infrequent plant loss risk, the old assigned value of 300 MW presumably takes into account the characteristics and generation connection arrangements existing at the time that this limit was assessed and assigned (in 2006). Unless some otherwise redundant additional bus section/coupler switchgear is incorporated within the power station main busbar arrangements, it is possible that with a typical (2xGT + 2xHRSG + 1xST) generation arrangement there is always the possibility that two GT s may be lost for a single contingency event, i.e. a bus-section or bus-coupler fault condition. Accordingly, in the case of the Sur power station it is likely that an infrequent plant loss risk at times of peak demand be about: 770 MW (2GTx220 MW GTs + 1x330 MW ST) when operating at rated capacity 850 MW (2GTx260 MW GTs + 1x330 MW ST) when operating at maximum capacity The infrequent plant loss risk at other times being dependent upon assumptions relating to generation dispatch, minimum techno-economic generation unit operating levels and also spinning reserve practices at times away from system peak demand. 8 SYSTEM STUDIES System studies have been performed to assess the dynamic performance of the MITS when it is subjected to various levels of loss of power infeed at Sur power station in the year 2015. The year 2015 is selected as the full generation (2000 MW) will be available at Sur throughout the year from January to December. The OETC DIgSILENT model is used in the studies. The objectives of the studies are to make sure that: The frequency is within the specified limits listed above in Table 2 The voltage is within the limits specified in the Grid Code [9] (±10% for 220 kv and 132 kv) before and after the loss of power infeed The new 400 kv voltage is within the standard limits of (±5%) before and after the loss of power infeed The system is stable before and after the loss of power infeed No overloading on any transmission component before and after the loss of power infeed No overloading on any generating unit before and after the loss of power infeed In all simulation studies, the following assumptions are considered: No infeed from external sources, so that the system depends on itself No load shedding is allowed No automatic generation control is available It should be noted that each of the above factor can help in limiting frequency and voltage variations resulting from loss of generation. Therefore, ignoring of these effects represents worst case conditions. The studies presented in this paper are corresponding to the following demand levels: Minimum demand of 1760 MW in 2015 A demand of 3000 MW in 2015 Peak demand of 5560 MW in 2015 The demand is taken to be the total generation export to the MITS required to cover the total loads connected at the grid stations, direct connected loads and transmission losses. Desalination and auxiliary loads are supplied locally at power stations and not included in the generation export demand. 9 RESULTS 9.1 System Performance at Minimum Demand Figures 4 (a) and (b) show the frequency and voltage responses to a generation trip of 390 MW at Sur IPP at minimum demand in 2015. This tripping causes a loss of 390 MW power infeed to the MITS resulting in unbalance between generation and load. Upon this loss of power infeed the frequency falls at a rate proportional to the difference between generation and load. The energy required to supply the excess load is taken from the energy stored in the rotating masses in the system (mainly turbines and generator rotors). This causes a decrease in the speed of generators and consequently decreases in the frequency. As a response to the speed/frequency decrease, the speed governors start acting to raise the power output of the generating units, thus decreasing the unbalance between generation and load and also decreasing the rate of fall of frequency. This process continues until the frequency reaches a minimum value of about 49.5 Hz as shown in Figure 4 (a). After a transient period of some damped oscillations, the frequency would settle to a new steady state value less than 50 Hz. Here, the limiting factor for the maximum infeed loss (390 MW) is the requirement to avoid a frequency deviation more than 0.5 Hz. In the absence of automatic frequency control, the LDC operators should normally act to restore the frequency over a longer period by calling for more generation from the power plants if load shedding is to be avoided. Figure 4 (b) shows the voltage responses at various busbars in the system. The transient and dynamic voltage variations are within acceptable limits.

Figure 5 (a) and (b) show the frequency and voltage responses to tripping generation of 500 MW at Sur IPP at minimum demand in 2015. For this level of infeed loss (500 MW), the frequency falls beyond the 49.5 Hz limit and reaches about 49.3 Hz. After a transient period of a few seconds, the frequency recovers to be within the 49.5 Hz limit. The period during which the frequency is being outside the 49.5 Hz is well less than 60 seconds. For a higher level of infeed loss (>500 MW), the loading on generators can exceed the maximum rating. Figure 5 (b) shows that the voltage responses are within acceptable limits. From the results shown in Figures 4 and 5, it could be suggested that: For a demand less than 2000 MW, the Normal Infeed Loss Risk is 390 MW For a demand less than 2000 MW, the Infrequent Infeed Loss Risk is 500 MW 9.2 System Performance at a Demand of 3000 MW Figures 6 (a) and (b) show the frequency and voltage responses to a generation trip of 780 MW at Sur IPP at a system demand of 3000 MW in 2015. For this level of infeed loss (780 MW), the frequency falls beyond the 49.5 Hz limit and reaches about 49.35 Hz. After a transient period of a few seconds, the frequency settles to be within the 49.5 Hz limit. As shown in Figure 6 (b), the voltage variations are within acceptable limits. The 780 MW infeed loss, may represent tripping either of: Three GTs of 260 MW each operating in open cycle configuration, i.e. 3x260MW=780M, Two GTs one from each block with associated ST, i.e. 2x(260MW+130MW)=780MW, or A combination of GTs and STs with a total generation of 780MW. Figures 7 (a) and (b) show the frequency and voltage responses to a generation trip of 500 MW at Sur IPP at a system demand of 3000 MW in 2015. The frequency deviation is within the 0.5 Hz and the voltage variations are within acceptable limits. From the results shown in Figures 6 and 7, it could be suggested that: For a demand more than 3000 MW, the Normal Infeed Loss Risk is 500 MW For a demand more than 3000 MW, the Infrequent Infeed Loss Risk is 780 MW From the above studies, it can be concluded that to facilitate connecting power plants with large generating units (260-330 MW) to the MITS the following revised definitions and values for the normal and infrequent infeed loss risks could be adopted: New Value of the Normal Infeed Loss Risk The new value of the Normal Infeed Loss Risk 500 MW at system demands above 3000 MW falling to 390 MW at system demands below 2000 MW. Infrequent Infeed Loss Risk The new value of the Infrequent Infeed Loss Risk is 780 MW at system demands above 3000 MW falling to 500 MW at system demands below 2000 MW. 9.3 System Performance at Maximum Demand The purpose of this section is to assess the system performance when operating at maximum summer peak demand of 5560 MW in 2015. Figure 8 (a) and (b) shows the system response to tripping of a complete block (A or B) of generation when operating at maximum output of 850 MW (2 GTs of 260 MW each + 1 ST of 330 MW) at Sur IPP. The frequency deviation is well within the 0.5 Hz and the voltage variations are within acceptable limits. 10 CONCLUSIONS The design of the arrangements for the connection of a large new power station such as the 2000 MW Sur IPP to the MITS needs to take into account the requirements of the OETC TSSS. The requirements with respect to generation connections are detailed in Section 3 of the TSSS. In the case of any large new power station it is important that the design of the connection arrangements includes measures to limit the potential loss of power infeed to the MITS as a result of an equipment failure or inadvertent switching operation. However, in order to ensure that appropriate connection arrangements are identified, and to avoid potentially nonsensical connection arrangements it is essential that the presently assigned normal and infrequent loss of power infeed limits are reviewed. Based upon the system studies and assessment presented in this report the following reviewed values of the normal and infrequent loss of infeed risks are proposed to facilitate the connection of the 2000 MW Sur IPP: Normal Infeed Loss Risk: That level of loss of power infeed risk which is covered over long periods operationally by frequency response to avoid a deviation of system frequency by more than 0.5Hz. Until reviewed in future this is 500 MW at system demands above 3000 MW falling to 390 MW at system demands below 2000 MW. Infrequent Infeed Loss Risk: That level of loss of power infeed risk which is covered over long periods operationally by frequency response to avoid a deviation of system frequency outside the range 49.5Hz to 50.5Hz for more than 60 seconds. Until reviewed in future this is 780 MW at system demands above 3000 MW falling to 500 MW at system demands below 2000 MW.

DIgSILENT DIgSILENT 50.125 50 49.875 49.750 49.625 49.500 49.375 2 Sur PS 220kV: Electrical Frequency in Hz Barka PS 220kV: Electrical Frequency in Hz SPS 220kV: Electrical Frequency in Hz Alkamil 132kV: Electrical Frequency in Hz New Ghubrah132kV: Electrical Frequency in Hz Manah132kV: Electrical Frequency in Hz Wadi Al Jazzi 132kV: Electrical Frequency in Hz Rusail 132kV: Electrical Frequency in Hz 3 Figure 4 (a): Frequency responses to 390 MW trip at Sur IPP at minimum demand. 1.12 1.08 1.04 0.96 0.92 0.88 2 Sur PS 220kV: Voltage, Magnitude in p.u. Barka PS 220kV: Voltage, Magnitude in p.u. SPS 220kV: Voltage, Magnitude in p.u. Alkamil 132kV: Voltage, Magnitude in p.u. New Ghubrah132kV: Voltage, Magnitude in p.u. Manah132kV: Voltage, Magnitude in p.u. Wadi Al Jazzi 132kV: Voltage, Magnitude in p.u. Rusail 132kV: Voltage, Magnitude in p.u. 3 Figure 4 (b): Voltage responses to 390 MW trip at Sur IPP at minimum demand.

DIgSILENT DIgSILENT 5 5 49.80 49.60 49.40 49.20 2 Sur PS 220kV: Electrical Frequency in Hz Barka PS 220kV: Electrical Frequency in Hz SPS 220kV: Electrical Frequency in Hz Alkamil 132kV: Electrical Frequency in Hz New Ghubrah132kV: Electrical Frequency in Hz Manah132kV: Electrical Frequency in Hz Wadi Al Jazzi 132kV: Electrical Frequency in Hz Rusail 132kV: Electrical Frequency in Hz 3 Figure 5 (a): Frequency responses to 500 MW trip at Sur IPP at minimum demand. 1.12 1.08 1.04 0.96 0.92 0.88 2 Sur PS 220kV: Voltage, Magnitude in p.u. Barka PS 220kV: Voltage, Magnitude in p.u. SPS 220kV: Voltage, Magnitude in p.u. Alkamil 132kV: Voltage, Magnitude in p.u. New Ghubrah132kV: Voltage, Magnitude in p.u. Manah132kV: Voltage, Magnitude in p.u. Wadi Al Jazzi 132kV: Voltage, Magnitude in p.u. Rusail 132kV: Voltage, Magnitude in p.u. 3 Figure 5 (b): Voltage responses to 500 MW trip at Sur IPP at minimum demand.

DIgSILENT DIgSILENT 5 5 49.80 49.60 49.40 49.20 2 Sur PS 220kV: Electrical Frequency in Hz Barka PS 220kV: Electrical Frequency in Hz sps 220kV: Electrical Frequency in Hz alkamil 132kV: Electrical Frequency in Hz New Gh-A132kV: Electrical Frequency in Hz Manah132kV: Electrical Frequency in Hz Wadi Al Jazzi 132kV: Electrical Frequency in Hz Rusail 132kV: Electrical Frequency in Hz 3 Figure 6 (a): Frequency responses to 780 MW trip at Sur IPP at 3000 MW demand. 1.04 1.02 0.98 0.96 2 Sur PS 220kV: Voltage, Magnitude in p.u. Barka PS 220kV: Voltage, Magnitude in p.u. sps 220kV: Voltage, Magnitude in p.u. alkamil 132kV: Voltage, Magnitude in p.u. New Gh-A132kV: Voltage, Magnitude in p.u. Manah132kV: Voltage, Magnitude in p.u. Wadi Al Jazzi 132kV: Voltage, Magnitude in p.u. Rusail 132kV: Voltage, Magnitude in p.u. 3 Figure 6 (b): Voltage responses to 780 MW trip at Sur IPP at 3000 MW demand.

DIgSILENT DIgSILENT 50.10 5 49.90 49.80 49.70 49.60 49.50 2 Sur PS 220kV: Electrical Frequency in Hz Barka PS 220kV: Electrical Frequency in Hz sps 220kV: Electrical Frequency in Hz alkamil 132kV: Electrical Frequency in Hz New Gh-A132kV: Electrical Frequency in Hz Manah132kV: Electrical Frequency in Hz Wadi Al Jazzi 132kV: Electrical Frequency in Hz Rusail 132kV: Electrical Frequency in Hz 3 Figure 7 (a): Frequency responses to 500 MW trip at Sur IPP at 3000 MW demand. 1.0375 1.0250 1.0125 00 0.9875 0.9750 0.9625 2 Sur PS 220kV: Voltage, Magnitude in p.u. Barka PS 220kV: Voltage, Magnitude in p.u. sps 220kV: Voltage, Magnitude in p.u. alkamil 132kV: Voltage, Magnitude in p.u. New Gh-A132kV: Voltage, Magnitude in p.u. Manah132kV: Voltage, Magnitude in p.u. Wadi Al Jazzi 132kV: Voltage, Magnitude in p.u. Rusail 132kV: Voltage, Magnitude in p.u. 3 Figure 7 (b): Voltage responses to 500 MW trip at Sur IPP at 3000 MW demand.

DIgSILENT DIgSILENT 50.10 5 49.90 49.80 49.70 49.60 49.50 2 Sur PS 220kV: Electrical Frequency in Hz Barka PS 220kV: Electrical Frequency in Hz sps 220kV: Electrical Frequency in Hz alkamil 132kV: Electrical Frequency in Hz New Gh-A132kV: Electrical Frequency in Hz Manah132kV: Electrical Frequency in Hz Wadi Al Jazzi 132kV: Electrical Frequency in Hz Rusail 132kV: Electrical Frequency in Hz 3 Figure 8 (a): Frequency responses to 850 MW trip at Sur IPP at summer peak demand. 1.075 1.050 1.025 0 0.975 0.950 2 Sur PS 220kV: Voltage, Magnitude in p.u. Barka PS 220kV: Voltage, Magnitude in p.u. sps 220kV: Voltage, Magnitude in p.u. alkamil 132kV: Voltage, Magnitude in p.u. New Gh-A132kV: Voltage, Magnitude in p.u. Manah132kV: Voltage, Magnitude in p.u. Wadi Al Jazzi 132kV: Voltage, Magnitude in p.u. Rusail 132kV: Voltage, Magnitude in p.u. 3 Figure 8 (b): Voltage responses to 850 MW trip at Sur IPP at summer peak demand.

11 ACKNOWLEDGEMENT The authors are grateful to Mr. Ali Al-Hadabi, CEO of the Oman Electricity Transmission Company for providing facilities to help performing the TSSS review studies. 12 REFERENCES [1] Oman Power & Water Procurement Company: OPWP s 7-Year Statement (2014-2020), (Available online) http://www.omanpwp.com.om [2] OETC: Transmission System Security Standard, (Available online) http://www.omangrid.com [3] DIgSILENT PowerFactory Software Website, http://www.digsilent.de [4] Authority for Electricity Regulation Website, http://www.aer-oman.org [5] OETC: The Annual Five-Year Transmission System Capability Statement (2014-2018) (Available online) http://www.omangrid.com. [6] O. H. Abdalla, Rashid Al-Badwawi, Hilal Al- Hadi, and Hisham Al-Riyami: Performance of Oman Transmission System with the 400 kv Gulf Cooperation Council Electricity Interconnection, Proceedings of the 2011 IEEE GCC Conference, Dubai, United Arab Emirates, 19-22 February 2011. (Available online) IEEE Xplore. [7] O. H. Abdalla, Hilal Al-Hadi, and Hisham Al- Riyami: Development of a Digital Model for Oman Electrical Transmission Main Grid, Proceedings of the 2009 International Conference on Advanced Computations and Tools in Engineering Applications, (ACTEA), NDU, Lebanon, 15-18 July, 2009, pp. 451-456. (Available online) IEEE Xplore. [8] P. Kundur, Power System Stability and Control, McGraw-Hill, Inc., 1994. [9] OETC, Grid Code, Version 2, (Available online) http://www.omangrid.com