Micro-grid to System Synchronization Based on Pre-Insertion Impedance Method (Version 1.0) By Peter Zhou University of Alberta Jan 30 th, 2015

Transcription

1 Micro-grid to System Synchronization Based on Pre-Insertion Impedance Method (Version 1.0) By Peter Zhou University of Alberta Jan 30 th, 2015

2 Outline 1. What is Synchronization? 2. Synchronization Concerns? 3. How Synchronization is Performed In Reality? 4. Synchronization Challenges 5. Project Proposal 6. Project Solutions I. Theoretical Explanation of Transients II. What is Acceptable Transient Level? III. Practical V and f Range for Open Loop IV. Procedure for Selecting Z V. Impedance Bypass Considerations 7. Other Problems Caused? I. Stability Consideration II. Reactive Power Imbalance III. Bypass transient due to Q Imbalance 8. Advantages of Open Loop 9. Future Work

3 1. What is Synchronization? Synchronization in simple terms is a process of connecting an electrical island to another. The electrical island can be a generator, a micro-grid, or part of a large power grid. There are 3 synchronization scenarios to consider: Generator synchronizes to system Micro-grid synchronizes to system System synchronizes to another system

4 2. Synchronization Concerns? To perform a successful synchronization, these parameters must be matched closely across both sides of the breaker: Voltage Magnitude Phase Angle Frequency V Poor synchronization can: Result in High Synchronizing Transient Current Result in generator out of synchronism with system I peak V Z eq

5 3. How is Synchronization Performed in Reality? In practice, all synchronizations require a way of feedback control Through feedback control, V across synchronizing breaker is minimized Feedback Control Generator to System: System ~ Generator Multi-DG Feedback Controls ~ Micro-grid to System: System Micro-grid ~ ~ System to System: The synchronization process can become complicated. Require sophisticated coordination and tuning of many generators.

6 4. Synchronization Challenges Consider in a rural area, DG is really far away from utility substation, feedback control is not the best option. Disadvantages: Long tuning process Costly to build Low Reliability over long distance due to attenuation/loss 30 miles long, it is a present situation of a real MW-scale Micro-grid located in a rural area of Rio de Janeiro state of Brazil.

7 4. Synchronization Challenges Restoration of islands is required after a blackout or major faults. Effective Coordination and time are crucial factors in play to minimize impacts on utility customers. Feedback control is difficult to implement during system restoration process. Stabilize any surviving islands Recover Generation Restore loads Energize Transmission Synchronize islands to each other An example of IESO s restoration strategy

8 5. Project Proposal The idea is to use an impedance pre-insertion to reduce the transients effects from synchronization. I peak V Z eq V Z insert +X d +X t +X eq Impedance Pre-insertion

9 6. Project Solutions I. Theoretical Explanation of Transients SG Superposition Across Breaker Grid Zstator Z Insertion Zsys Local Load Assumptions: Constant Z type Load Grid as swing bus Zsys is the system short circuit impedance SG Zeq Grid Zs I Transient Zse Zsys X d

10 6. Project Solutions I. Theoretical Explanation of Transients Following analytical equations were derived based on the transient circuit of superposition. Closing transient is primarily a function of V, δ, and Z eq Z eq is equivalent impedance seen at breaker I peak is the max current among three phases VA IsyncA( t) sin( wt A ) sin( A ) e Z eq VB IsyncB ( t) sin( wt B ) sin( B ) e Z eq VC IsyncC ( t) sin( wt C ) sin( C ) e Z eq Rt / L Rt / L Rt / L I peak V Z eq V Z insert +X d +X t +X eq Impedance Pre-insertion

11 Te (pu) I Stator (pu) I sync (pu) 6. Project Solutions II. What is the acceptable transient level? According to IEEE standards C50.12 and C50.13, the synchronization criteria for both cylindrical and salient-pole synchronous generators are: Angle ±10 Voltage 0 to 5 % Slip ±0.067Hz If within IEEE standards, the maximum transients will be in an acceptable level: 1 0 Synchronizing Transients pu 1.91pu I peak =0.932 pu for synchronizing transient T e =0.91pu Reference Torque deviation pu time (s)

12 6. Project Solutions III. Practical V and f Range for Open Loop Busses inside both electrical islands to be synchronized have their voltages and frequencies inside a practical range that was decided by the utility protocol. The boundary conditions for voltage and frequency based on the practical range determine the worst case transients possible for open loop. After knowing the worst transients, the impedance size can be determined either by analytical approach or EMTP simulations. θ = 10 is the IEEE standard value. However, in most cases, faulty synchronization could happen due to higher than expected slip and breaker mechanism delay, a worst case of θ = 30 is assumed. Generator, Microgrid 1 2 Bulk Grid Table 1: Practical V and f Ranges Based on AIES Standard Vmin~Vmax (pu) Fmin~Fmax (Hz) Micro-grid (bus 1) 0.9~ ~60.2 System (bus 2) 0.9~ ~60.05

13 6. Project Solutions IV. Procedure for Selecting Z Start Run Load Flow (breaker Open) Based on AIES standard, worst case open loop synchronization scenario is determined as: V = 0.2pu Adjust Xfmer tap, local loading to match IEEE Synchronization Criteria o (5%,10,0.067 Hz) Adjust Xfmer tap, local loading to match Worst case open loop Synchronization Criteria o (20%,30,0.35 Hz) θ = 30 f = 0.35Hz Run EMTP Simulation with disturbance (Closing breaker) Run EMTP Simulation with disturbance (Closing breaker) Re-run Iopen loop> I? IEEE No Stop Obtain Z Yes Add Impedance at synchronization link (Initial Guess of Z obtained from Analytical solution)

14 6. Project Solutions IV. Procedure for Selecting Z Bottom figure is a comparison between analytical and EMTP simulation results of I peak Vs θ. They come to close agreements. θ is the primary factor that affects I peak when θ > 10. f = 0.35Hz has negligible impact on I peak.

15 6. Project Solutions IV. Procedure for Selecting Z The impedance to be inserted is selected based on the intersection of synchronizing transient curve with the acceptable reference line. As an example, Z=0.556 (pu) or 16.6 ohm is needed to limit the maximum transient level to be within the acceptable level incurred by V = 0.1pu, θ = 30, and f = 0.35Hz

16 6. Project Solutions V. Impedance Bypass Impedance bypass is required to avoid excessive energy dissipation due to the impedance insertion and restores the transmission line capacity back to its original state. After synchronization, the generator starts to have electromechanical oscillations. In order to bypass the impedance, it is desirable to wait for generator electromechanical oscillations to reach a steady state first. This way, a minimum voltage is seen across breaker 2, which guarantees a minimum bypass transient. V Micro-grid Generators BRK1 BRK2 Z Insertion Steady Power Flow Bulk Grid V1 P R 2 2 V1 V2 cos( ) XV2 sin( ) R X V1 Q RV sin( ) X V 1 V2 cos( ) R X

17 Switching Transients (pu) 6. Project Solutions V. Impedance Bypass Steady state P flow is caused by a micro-grid frequency different from the system frequency, which results in DG s change in mechanical power. Steady state Q flow is caused by the unmatched voltage magnitudes across the breaker. 3 Bypassing Under Different Conditions of V, f Frequency 5% droop 2.5 V 10%, 30 o Synchronizing Transient 2 f o Optimal Impedance = 16.6 ohm f s f 1.5 V 10%, f 0.35Hz P 1 V 0, f 0.35Hz 0.5 Bypass Transient V 10%, f 0.25Hz V 0, f 0.25Hz Power Output P o P Inserted Impedance (ohms)

18 7. Other Problems Caused? I. Stability Consideration Impedance insertion leads to further rotor angle advancements. But by how much? θ and f have most impact on transient stability of generator Inclusion of governor model can reduce the effects of f as shown due to changing Pm. Even in the worst case scenario, the generator remains angular stable. The max δ deviation is 5 when maximum impedance per unit is inserted. Micro-grid Frequency (Hz) System Frequency (Hz) f (Hz) 60.2 (max) (min) (min) (max) -0.35

19 7. Other Problems Caused? I. Stability Consideration The Inertia constant H of the generator will have an effect on the rotor angle deviation: Higher the H means higher the initial kinetic energy of rotor Initial kinetic energy can cause further rotor advancement in the transient swing due to f Doubling the H value with f = 0.35Hz in the worst case has negligible impact on the stability of generator. H = 2.52s

20 7. Other Problems Caused? II. Reactive Power Imbalance Reactive power imbalance is a concern after bypassing the impedance. Reactive power will flow from the side of higher voltage magnitude to the lower voltage magnitude bus. A result from high V difference across breaker. Consequences: 1. Sudden over-excitation or under-excitation of the field current. Both situations should be avoided to prevent heating or damage to the field windings and end iron core. Q I f I s P End Region Heating 2. Power quality concern. For example, voltage swells or sags that may affect some sensitive loads in the area.

21 7. Other Problems Caused? II. Reactive Power Imbalance Reactive power will flow from the side of higher voltage magnitude to the lower voltage magnitude bus. Reactive power imbalance not much a concern after synchronization because the inserted impedance is there to limit the amount of Q flow. However, after bypass, the Q flow will be a concern if voltage magnitudes not matched properly. One consequence of Q imbalance can result in a sudden over-excitation or underexcitation of the field voltage. Both situations should be avoided to prevent heating or damage to the field windings and end iron core. Second concern over reactive power imbalance is related to power quality. For example, voltage swells or sags that may affect some sensitive loads in the area. Although it is a secondary concern if no equipment damage occurs. Due to the reactive power imbalance, it is strongly suggested to run load flow after closing the synchronizing breaker to check any nearby generators have reached their reactive capability limit. Relief small island loading and/or restore more loading in the larger island could be a way to mitigate the problem by pre-determine the loading profile of both islands.

22 Peak Current (pu) 7. Other Problems Caused? III. Bypass Transients due to Q Imbalance Bypass transients is over the acceptable level at all impedance values when V = 0.2pu in the worst case. Recommendations: Adjust AVR settings to match the Q of local loads. (Voltage following mode for DGs) Run load flow first to pre-determine a load profile for both micro-grid and system so that generators will not go beyond its Qmax & Qmin Synchronizing Curve V 20%, 30 o Analytical Simulation Reference Line Bypass Curve V 20%, f 0.25Hz Optimal Z = ohm Inserted Impedance (ohm)

23 8. Advantages of Impedance Based Synchronization Idea of impedance insertion can mitigate the synchronizing transients from synchronization. If the busses of islands are inside the practical range of V and f, then open loop synchronization without feedback control can be implemented with impedance preinsertion. This approach eliminates the need for a feedback control of generators. It is beneficial in the following ways: No need to build a communication line when DG is far away from the switchyard. Improves reliability in the case of power outage. No need to spend the time to tune/control the DGs if bus V and f are in the practical range. Faster synchronization process results in faster system restoration.

24 9. Future work: Impedance based synchronization method shall be investigated between system to system. In the system to system synchronization scenario, can one determine the size of impedance still by the analytical approach? If so, is there a way to simplify or reducing the networks in a way to easily find the impedance?

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26 Open Loop Micro-grid to System Synchronization Based on Pre-Insertion Impedance Method (Final Version) By Peter Zhou University of Alberta Jan 30 th, 2015

27 Outline 1. Synchronization Concerns 2. Current Practice for Performing Synchronization 3. Synchronization Issues 4. New Idea --- Open Loop Synchronization 5. Research Strategy 6. Solutions 7. Conclusions 8. Future Works

28 1. Synchronization Concerns Synchronization in simple terms is a process of connecting an electrical island to another. The electrical island can be a generator, a micro-grid, or part of a large power grid. There are 3 synchronization scenarios to consider: Generator synchronizes to system Micro-grid synchronizes to system System synchronizes to another system

29 1. Synchronization Concerns Synchronization without any control may result in damage of generator and prime mover due to High Synchronizing Transient Current generator out of synchronism with system How to deal with them? Challenge

30 2. Current Practice for Performing Synchronization Adjust the voltage phasor difference across the breaker into an acceptable range during synchronization process through feedback. V ΔV --- difference of voltage magnitude Δθ --- difference of voltage phase angle Δf --- difference of frequency (IEEE criteria) Limit Transient Current Limit Torque deviation I peak V Z eq Ensure stability

31 2. Current Practice for Performing Synchronization Feedback Control Generator to System: System ~ Generator Multi-DG Feedback Controls ~ Micro-grid to System: System Micro-grid ~ ~ System to System: The synchronization process can become complicated. Require sophisticated coordination and tuning of generators on both sides.

32 3. Synchronization Issues Micro-grid Bulk Grid Sync Panel 25 ~ Synchronizing Control Communication Link Issues: A costly communication link must be build when a DG is far away from PCC. Feedback control is not reliable in the extreme case of power outage. Feedback control may need an inacceptable long time to tune the generators, when system restoration at emergency is required.

33 4. New Idea --- Open Loop Synchronization New Idea: Using an impedance pre-insertion to reduce the transients effects from synchronization instead of adjusting V through feedback. I peak V V Z eq Z insert +X d +X t +X eq The impedance is designed to meet the synchronization requirement, based on a pre-defined voltage and frequency range of the islands to be synchronized together, such that the open loop synchronization can be achieved. Z IEEE or utility criteria synchronization requirements Ipeak, ΔTe must remain the same level Circuit Breaker fg ( Hz) 60.2 Generator, Microgrid 1 2 Bulk Grid ( Hz) 0.9 Pre-established Pre-established Vg ( pu) Operating Region Operating Region fs Vs ( pu) 59.7

34 4. New Idea --- Open Loop Synchronization Feedback Control System ~ No Watch V, θ, f Meet Criteria for V, f? Yes Watch θ θ<criteria? Generator Yes Close Synchronizing Breaker No Close Loop Feedback Z Circuit Breaker fg ( Hz) 60.2 Generator, Microgrid Bulk Grid 0.9 Pre-established Pre-established Vg ( pu) Operating Region Operating Region fs ( Hz) Vs ( pu) Each party operates within preestablished operating region (i.e. power quality limits) Verify if V and f are within the region at the breaker location Yes Watch θ θ<criteria? Yes Close Synchronizing Breaker No Open Loop No Bypass Impedance Can t perform Synchronization

35 5. Research Strategies Problems What is the acceptable transient level? Strategies Use IEEE C50.12 criteria for generator synchronization to establish acceptable transients level. How to select the impedance to control switching transient? Use common utility operating limits for voltage and frequency to establish open loop criteria. Is the impedance bypass transient acceptable? Evaluate the bypass transients to establish the number of steps or impedance values for bypassing operation Can the generator reach stable condition? Establish a method or criterion to determine the impact on stability

36 Electromagnetic Torque Te (pu) Stator Current (pu) 6. Solutions Acceptable transient level According to IEEE standards C50.12 and C50.13, the synchronization criteria for both cylindrical and salient-pole synchronous generators are: Angle ±10 ; Voltage 0 to 5 %; Slip ±0.067Hz Current and torque transients experienced by a generator under the above condition is considered acceptable. Therefore, the limits on transients can be established by determining the maximum transient under the above conditions For example, simulation study reveals (Based on C50.12 standards): I peak =0.537 pu for stator current transient T e =Te max Te ss = =0.572pu Time (s) Time (s)

37 6. Solutions Impedance selection Each party is expected to operate within established limits that meet the power quality requirements of respective systems, as illustrated below: V min ~V max (pu) f min ~f max (Hz) Micro-grid (bus 1) 0.9~ ~60.2 System (bus 2) 0.9~ ~60.05 Generator, Microgrid 1 2 Bulk Grid Limit on Δθ: θ is monitored at the synchronization point. The limit on θ is selected to be the same as that use for close-loop synchronization, which is 10 degrees difference. Objective of Impedance Selection: Find minimal Z that leads to acceptable transients levels (inrush current and torque limits) under above synchronizing conditions.

38 6. Solutions Impedance selection Research Method for Impedance Selection: Step 1. Determine all possible worst case synchronization scenarios based on pre-established power quality limits of the two parties. Step 2. Evaluate the worst case transients (Torque and Current) resulting from synchronization scenarios above. Step 3. Design an impedance value for insertion such that the highest transient is within the acceptable level.

39 6. Solutions Impedance selection Research Method Step 1 (Worst case synchronization scenarios): Ideally, synchronization wants to take place when V1=V2, θ1=θ2, f1=f2, two parties will synchronize with perfect parallelization with no switching transients and no system disturbances at all. Case 1 represents the reference case for acceptable transients. Possible worst case synchronizations will take place in following cases 2-5 shown in Table 1, which the operating points of both parties deviate the most from normal operation (1pu, 60Hz), and synchronize at a maximum allowable voltage and frequency differences. 0.9pu f Hz Hz 3 1.1pu V 1 0.9pu f Hz Hz 1.1pu V 2 Table 1: Synchronization Scenarios V1 (pu) V2 (pu) f1 (Hz) f2 (Hz) θ=θ1-θ2 (deg) case case case case case

40 Torque and Current Deviation (pu) 6. Solutions Impedance selection Research Method Step 2 (Worst case transients evaluation): System under study: SUB V2,f2 CB V1,f1 15 miles 15 miles 25/4.16kV Yg/Yg SG 6.6MVA 25kV 346MVA 2.0MW 0.65MVAr Assumptions: micro-grid is operating at near full load as a worst case. Worst transient case: Highest current and torque transient is located in case MW 0.65MVAr MW 0.65MVAr case1 case2 case3 case4 case5 case Te Ipeak Fig: Torque and current peak deviations when not controlled by impedance insertion.

41 6. Solutions Impedance selection Research Method Step 3 (Impedance Design Procedure to Reduce Worst Case Current Transient): Case Study File (reference case) Case Study File (worst case) Establish V1,V2,f1,f2 and θ across open breaker (Initialize by loadflow) Calculation Acceptable transient level (I & Te) Establish V1,V2,f1,f2 and θ across open breaker (Initialize by loadflow) Calculation Z f ( I, V, V, f, f, ) acceptable Impedance Z is determined by analytical solution. The accuracy of the analytical solution is verified by numerous transient simulations.

42 6. Solutions Impedance selection Analytical method for determination of Impedance Z Superposition Across Breaker Micro-grid Generators Bulk Grid Following analytical equations were derived based on the transient circuit of superposition: For simplicity, assuming f1=f2 (same frequency) VA IsyncA( t) sin( wt A ) sin( A ) e Z eq VB IsyncB ( t) sin( wt B ) sin( B ) e Z eq VC IsyncC ( t) sin( wt C ) sin( C ) e Z Where: eq V V V V V A B c 1 tan ( wl / R) 1 2 A ( V1 V2) Rt/ L Rt/ L Rt/ L V1, f1 V2, f2 Z eq is the total equivalent series impedance seen by the breaker. Z insertion is determined by subtracting all other system equivalent impedances such as transformer, line, and generator sub-transient reactance. Z f ( I, V, V, ) insertion acceptable 1 2

43 Stator Current (pu) Stator Current Deviation (pu) Torque and Current Deviation (pu) 6. Solutions Impedance selection Analytical & Simulation results for determination of Impedance Z Analytical solution results in a Z insertion value of 0.23 pu (21.8 ohm). Analytical current waveform is closely matched to the simulation within the first cycle after breaker is closed. With this designed impedance, both current and torque transient disturbances are within the reference level that comply with IEEE synchronization criteria Z=0.23pu Simulation (case 2) Analytical (case 2) Reference case Z Insertion=0.23pu Impedance Insertion Value (pu) Phase A (simulation) Phase A (Analytical) Time (s) case1 case2 case3 case4 case5 Te Ipeak Fig: Torque and current peak deviations when controlled by a designed impedance insertion. Note: cases 4 and 5 have relatively lower excitation compare to 2 and 3, therefore the P-δ transient curve is lower so the power and torque transient swing is smaller.

44 7. Bypass Transients Impedance bypass is done after the system has reached to a new steady-state. The process of bypass also produces current and torque transients. These transients must not exceed the allowable limits as well. Method adopted to evaluate the bypass transient is shown below. Bypass Transient Evaluation Method: 1. Evaluate the steady state real and reactive power imbalance between the two parties after synchronization, when both parties synchronizes within the operating limits pre-established. 2. Evaluate the worst bypass scenario based on worst resulting voltage phasor difference across the inserted impedance V, since I bypass V. 3. Determine and verify that whether if the worst bypass transient is below the allowable limit.

45 Reactive Power Imbalance (pu) 7. Bypass Transients Evaluation Step 1 (Evaluate Steady state P&Q Imbalance): Real and reactive power imbalance is mainly due to a frequency difference and voltage magnitude difference prior to synchronization. ( f P m, V Q) The real and reactive power imbalance will incur a current flowing through the impedance, and therefore incur a voltage drop across the impedance. Therefore, it is true that higher the power imbalances, the higher the voltage across the impedance and hence, the higher the bypass transient Z=0.23pu Segment 1-3 and 2-4 is obtained by fixing V1 and V2 but vary f1 ( ) and f2 ( ) Segment 1-2 and 3-4 is obtained by fixing f1 and f2 but vary V1 ( ) and V2 ( ) Active Power Imbalance (pu)

46 Reactive Power Imbalance (pu) 7. Bypass Transients Evaluation Step 2 (Evaluate worst bypass scenario): Since the V across the impedance is dependent on S = P 2 + Q 2, worst bypass scenarios can be evaluated by the worst power imbalances shown by 4 cases in the figure. V = Z I = Z (S/V1), with V1 1pu, V is proportional to both the impedance size Z and the power imbalance S. Based on figure below, there are 4 possible cases where the bypass transient are the highest Z=0.23pu Active Power Imbalance (pu)

47 Reactive Power Imbalance (pu) 7. Bypass Transients Evaluation Step 2 (Evaluate worst bypass scenario): Z=0.23pu V1 (pu) V2 (pu) f1 (Hz) f2 (Hz) Case Case Case Case Active Power Imbalance (pu) BRK2 Impedance Switching (BRK1 Closes) Micro-grid Generators V Z Insertion BRK1 1 1 V2 2 Bulk Grid Determine largest voltage difference across impedance ( V) (by power flow) Real Power (pu) Reactive Power (pu) S (pu) V over Z (pu) Case Case Case Case Worst bypass scenario is Case 1

48 Electric Torque Te (pu) Stator Current (pu) 7. Bypass Transients Evaluation Step 3 (Verify worst case bypass transient is within allowable limits): Time (s) Impedance switching Impedance switching Impedance bypass Impedance bypass Time (s) Impedance is bypassed at a worst bypass scenario according to case 1 conditions. Bypass transients (current and torque) is no more severe than the allowable limits in the worst case, in fact, it is quite small due to a small voltage drop across the impedance. After the bypass, the stator current is over 1 per unit, which suggests a machine overloading primarily due to the reactive power imbalance. This is more of a power quality concern and a secondary concern if no sensitive equipment are damaged.

49 8. Transient Stability Assessment Transient stability is the ability of the power system to maintain in synchronism when subjected to a transient disturbance, in this case, micro-grid to system synchronization. In the proposed open loop synchronization approach, there are 2 expected switching (disturbances) to the power system, one is the first impedance switching, and the second is the impedance bypass switching. Both disturbances must remain in rotor angle stable, therefore, will be assessed individually by examining their maximum rotor angle deviation δ_max. Transient Stability Assessment Impedance Switching Bypass Switching Worst case δ_max deviation based on power quality limits of open loop synchronization scheme? Using Equal Area criterion for transient stability assessment of bypass operation Sensitivity Study to show the impact of different loading levels and machine inertia values on δ_max

50 8. Transient Stability Assessment Method to analyze Micro-grid to System Synchronization phenomenon: For the impedance switching, it is important to realize that there is no power transfer between the micro-grid to system prior to breaker closes. After breaker is closed, although steady state active power transfer is non-zero due to the governor droop setting of the machine, but in the transient time period, Pe steady state can be assumed to be zero. In other words, Pm=Pe ss =0. At the instant when breaker is closed, the transient Pmax is determined by Vth, Vsys, and Zeq seen across breaker (assume loads are modelled as constant impedance). Sudden loading of the micro-grid generator is determined by the instant loading angle, which is the instantaneous angle difference when breaker is closed. The rotor angle and rotor speed behaviors due to the impact of impedance switching can be best explained by the Equation of Motion or the Swing Equation. Micro-grid can be best viewed as an Equivalent Machine through the reduction of Thevenin equivalence. Micro-grid Impedance Switching V Z th th System Equivalent Machine Pe 0 V sys sys

51 Rotor Deviation Power Transfer Pe Rotor Frequency (Hz) 8. Transient Stability Assessment Impedance Switching Impact on Transient Stability (Power Angle Relationship): 2H d 2 δ(t) ω syn dt 2 = P mp.u P ep.u H ω syn dδ dt 2 δmax δ max = (P δ mp.u P ep.u )dδ 0 δ 0 δ max = cos 1 cos(δ o ) H W syn 2π f gen f sys 2 X th + X insert + X sys V th V s max o P max Vth V X eq sys Wr Wsyn Begin Synchronization (Breaker closed) In practice,due to dynamics of field and damping winding, the electromechanical oscillation is damped and stabilized Rotor angle starts increasing due to higher micro-grid frequency than system frequency Time (s) o o max min o Initial Angle difference at across breaker ss Power Angle (deg) max min min Time (s)

52 δ max (deg) 8. Transient Stability Assessment Worst case δ_max due to Impedance Switching (with constant Ef): 4 cases are worth to consider to investigate the worst case δ based on power quality limits. Cases F1 (Micro-grid Frequency) Hz F2 (System Frequency) Hz V1 (pu) V2 (pu) θ=θ 1 θ 2 (Deg) Worst case With Constant Ef case1 case2 case3 case4 Fig: Impedance used equals 0.23pu, with Micro-grid loading level= 85%. Maximum δ occurs in cases 3 and 4 are primarily due to an initial large speed deviation between the Micro-grid to system. Cases 3 and 4 have a larger first swing because f= Hz, which the speed differential represents the initial kinetic energy offset in the rotor.

53 δ max (deg) 8. Transient Stability Assessment Worst case δ_max due to Impedance Switching (with Excitation control AVR): 3 cases are worth to consider to investigate the worst case δ based on power quality limits and AVR control Cases 27.8 F1 (Micro-grid Frequency) Hz F2 (System Frequency) Hz V1 (pu) V2 (pu) θ=θ 1 θ 2 (Deg) case1 case2 case3 δ max (const Ef) δ max (AVR) 36.4 Fig: Impedance used equals 0.23pu, with Micro-grid loading level= 85%. Worst case As can be seen from figure, with the addition of AVR excitation control, during transient, it can either help or aggravate the rotor angle advancement depending on the relative magnitude of system voltage. IEEE type 1 exciter and voltage regulator is implemented. In case 3, rotor advancement increases due to AVR is because although system voltage is on the higher end (1.1pu), but the AVR lowers the field voltage set point automatically due to an injecting Q from the system. Worst case With AVR

54 Max transient Rotor Deviation (deg) Max Transient Rotor Angle Deviation (Deg) 8. Transient Stability Assessment Sensitivity study of Micro-grid Loading level and Machine Inertia effects on δ_max: Z=0.23pu Z=0.3pu Z=0.4pu H=1.26 H=2.52 H= % 20% 30% 40% 50% 60% 70% 80% Percentage Loading of Micro-grid Fig: Loading effects for case3 synchronizing condition with AVR control The mechanical Pm of the machine increases as the loading of the Micro-grid increases. With AVR controlling the Q out of the machine by adjusting the field voltage, in case 3, maximum power transfer capability decreases after impedance switching due to a Q flow from the system side. As a result, the steady state Load angle of the machine increases, which also affects the transient rotor angle deviation due to AVR % 20% 30% 40% 50% 60% 70% 80% Percentage of Micro-grid Loading Level Fig: Sensitivity Study of the effect of Machine Inertia (H) on transient stability, Z=0.23pu, case 3 Effect of H can be explained through the fundamental equation of motion. For a 3-phase to ground terminal fault, H can improve stability by reducing the amount of rotor advancement when rotor is accelerating. However, for synchronization, higher H may aggravate the rotor advancement primarily due to the initial kinetic energy stored within the rotor due to f across breaker. Thus, for small inertia machines within the micro-grid, the machine will most likely to be stable for all loading levels if synchronized within the power quality limits.

55 Rotor Angle (Deg) Power Transfer Pe 8. Transient Stability Assessment Impedance Bypass Impacts on Transient Stability: Micro-grid V Z th th Bypass Switching System Pe ss Pmax increased due to a decreased in Zeq Equivalent Machine Pe ss V sys sys Power Angle (deg) Bypass Impedance can be seen as a way to improve the system stability by increasing maximum power transfer. Bypass operation should be always rotor angle stable since the steady state Pe is close to zero before the bypass. In addition, the δ max for bypass is considered a much smaller disturbance than the first switching due to δ o 10 and f= Impedance Switching Bypass Time (s)

56 9. Conclusion Open loop synchronization is based on pre-defined power quality limits can be implemented with an impedance insertion at the PCC to limit the inrush current within an acceptable level. In practice, voltage levels of either the Micro-grid or the system should meet the voltage and frequency range requirements as defined by the power quality protocol at all times. Synchronization transient current and torque disturbances are quite similar to that of a short circuit/fault problem, which can be analyzed with similar procedure. Transient stability analysis of Micro-grid to system synchronization problem may be analyzed using the Equal Area Criterion and the Equation of Motion by an analogy to single machine to infinite bus case. As a general finding, loading levels of the Micro-grid have negligible effects on the transient current and torque due to synchronization. A properly designed impedance can limit the worst case transient inrush current without incurring a significant impact on the transient stability (rotor deviation).