Micro-grid to System Synchronization
Based on Pre-Insertion Impedance Method
(Version 1.0)
By
Peter Zhou
University of Alberta
Jan 30th , 2015
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
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
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
Poor synchronization can:
• Result in High Synchronizing Transient Current
• Result in generator out of synchronism with system
𝐼𝑝𝑒𝑎𝑘 ∝ ∆𝑉
𝑍𝑒𝑞
∆𝑉
3. How is Synchronization Performed in Reality?
Generator to System: System ~
Feedback Control
Generator
• In practice, all synchronizations require a way of feedback control
• Through feedback control, ∆𝑉 across synchronizing breaker is minimized
Micro-grid to System: System Micro-grid
~
~
~
Multi-DG Feedback Controls
System to System:
• The synchronization process can become complicated.
• Require sophisticated coordination and tuning of many generators.
4. Synchronization Challenges
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.
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
• 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
Energize Transmission
Restore loads
Synchronize islands to each other
An example of IESO’s restoration strategy
4. Synchronization Challenges
5. Project Proposal
• The idea is to use an impedance pre-insertion to reduce the transients effects
from synchronization.
𝐼𝑝𝑒𝑎𝑘 ∝
∆𝑉
𝑍𝑒𝑞 ∝
∆𝑉
𝑍𝑖𝑛𝑠𝑒𝑟𝑡+𝑋𝑑′′+𝑋𝑡+𝑋𝑒𝑞
Impedance
Pre-insertion
6. Project Solutions I. Theoretical Explanation of Transients
Assumptions:
Constant Z type Load
Grid as swing bus
Zsys is the system short circuit impedance
𝑋𝑑′′
SG Grid
ZeqZsys
I Transient
Zs Zse
SG Grid
SuperpositionAcross Breaker
Zstator Zsys
Local Load
Z Insertion
• Following analytical equations were derived based on the transient circuit of superposition.
• Closing transient is primarily a function of ∆𝑉, ∆𝛿, 𝑎𝑛𝑑 𝑍𝑒𝑞
• 𝑍𝑒𝑞 is equivalent impedance seen at breaker
/
/
/
( ) sin( ) sin( )
( ) sin( ) sin( )
( ) sin( ) sin( )
Rt LAsyncA A A
eq
Rt LBsyncB B B
eq
Rt LCsyncC C C
eq
VI t wt e
Z
VI t wt e
Z
VI t wt e
Z
𝐼𝑝𝑒𝑎𝑘 is the
max current
among
three phases
6. Project Solutions I. Theoretical Explanation of Transients
𝐼𝑝𝑒𝑎𝑘 ∝ ∆𝑉
𝑍𝑒𝑞 ∝
∆𝑉
𝑍𝑖𝑛𝑠𝑒𝑟𝑡+𝑋𝑑′′+𝑋𝑡+𝑋𝑒𝑞
Impedance
Pre-insertion
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:
0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1-1
0
1
I sync (
pu)
Synchronizing Transients
0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1-2
0
2
I S
tato
r (p
u)
0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 10
1
2
time (s)
Te (
pu)
0.932pu
1.91pu
1.91pu
• 𝐼𝑝𝑒𝑎𝑘=0.932 pu for
synchronizing transient
• ∆𝑇𝑒=0.91pu Reference
Torque deviation
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.
Vmin~Vmax (pu) Fmin~Fmax (Hz)
Micro-grid (bus 1) 0.9~1.1 59.7~60.2
System (bus 2) 0.9~1.1 59.95~60.05
Bulk Grid Generator,
Microgrid
1 2
Table 1: Practical V and f Ranges Based on AIES Standard
Based on AIES
standard, worst case
open loop
synchronization
scenario is
determined as:
• ∆𝑉 = 0.2𝑝𝑢
• ∆𝜃 = 30°
• ∆𝑓 = 0.35𝐻𝑧
6. Project Solutions IV. Procedure for Selecting |Z|
Start
Run Load Flow (breaker Open)
Adjust Xfmer tap, local loading to matchWorst case open loop Synchronization Criteria
(20%,30 ,0.35 )o Hz
Adjust Xfmer tap, local loading to matchIEEE Synchronization Criteria
(5%,10 ,0.067 )o Hz
Run EMTP Simulation with disturbance (Closing breaker)
Run EMTP Simulation with disturbance (Closing breaker)
> ?open loopI IEEEI
Add Impedance at synchronization link(Initial Guess of |Z| obtained from
Analytical solution)Yes
Re-run
No
StopObtain |Z|
6. Project Solutions IV. Procedure for Selecting |Z|
• Bottom figure is a comparison between analytical and EMTP simulation results
of 𝐼𝑝𝑒𝑎𝑘𝑉𝑠 ∆𝜃. They come to close agreements.
• ∆𝜃 is the primary factor that affects 𝐼𝑝𝑒𝑎𝑘 when ∆𝜃 > 10°.
• ∆𝑓 = 0.35𝐻𝑧 has negligible impact on 𝐼𝑝𝑒𝑎𝑘.
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
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.
Micro-grid
GeneratorsBRK1
Z Insertion
BRK2
Bulk Grid
Steady PowerFlow
V
11 2 22 2
12 1 22 2
cos( ) sin( )
sin( ) cos( )
VP R V V XV
R X
VQ RV X V V
R X
Frequency
Power Output
of
oP
sf
1P
5% droop
P
f
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.
0 5 10 15 20 25 30 35 400
0.5
1
1.5
2
2.5
3
Inserted Impedance (ohms)
Sw
itchin
g T
ransie
nts
(pu)
Optimal Impedance = 16.6 ohm
10%, 0.35V f Hz
0, 0.35V f Hz
10%, 0.25V f Hz
0, 0.25V f Hz
10%, 30oV
Bypassing Under Different Conditions of ,V f
Synchronizing
Transient
Bypass Transient
• 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 0.556
per unit is inserted.
7. Other Problems Caused? I. Stability Consideration
Micro-grid Frequency (Hz) System Frequency (Hz) ∆𝒇 (Hz)
60.2 (max) 59.95 (min) 0.25
59.7 (min) 60.05 (max) -0.35
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.
7. Other Problems Caused? I. Stability Consideration
𝐻 = 2.52𝑠
• 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.
2. Power quality concern. For example, voltage swells or sags that may affect
some sensitive loads in the area.
7. Other Problems Caused? II. Reactive Power Imbalance
Q fI
sI
End Region Heating
P
• 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 under-excitation 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.
7. Other Problems Caused? II. Reactive Power 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.
7. Other Problems Caused? III. Bypass Transients due to Q Imbalance
0 5 10 15 20 25 30 35 400.5
1
1.5
2
2.5
3
Inserted Impedance (ohm)
Peak C
urr
ent
(pu)
Analytical
Simulation
Reference LineSynchronizing Curve
Optimal |Z| = 18.87 ohm
Bypass Curve
20%, 30oV
20%, 0.25V f Hz
• 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 pre-
insertion.
• 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.
8. Advantages of Impedance Based Synchronization
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?
Open Loop Micro-grid to System
Synchronization Based on Pre-Insertion
Impedance Method
(Final Version)
By
Peter Zhou
University of Alberta
Jan 30th , 2015
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
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
1. Synchronization Concerns
• damage of generator and prime mover due to High Synchronizing Transient Current
• generator out of synchronism with system
Synchronization without any control may result in
How to deal with them?
Challenge
𝐼𝑝𝑒𝑎𝑘 ∝ ∆𝑉𝑍𝑒𝑞
∆𝑉
• ΔV --- difference of voltage magnitude
• Δθ --- difference of voltage phase angle
• Δf --- difference of frequency
Adjust the voltage phasor difference across the breaker into an acceptable
range during synchronization process through feedback.
2. Current Practice for Performing Synchronization
Limit Torque deviation
Ensure stability
Limit Transient Current
(IEEE criteria)
2. Current Practice for Performing Synchronization
Generator to System: System ~
Feedback Control
Generator
Micro-grid to System: System Micro-grid
~
~
~
Multi-DG Feedback Controls
System to System:
• The synchronization process can become complicated.
• Require sophisticated coordination and tuning of generators on both sides.
3. Synchronization Issues
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.
Bulk Grid
~
Micro-grid
25
Synchronizing Control
Sync Panel
Communication Link
4. New Idea --- Open Loop Synchronization
𝐼𝑝𝑒𝑎𝑘 ∝ ∆𝑉
𝑍𝑒𝑞 ∝
∆𝑉
𝒁𝒊𝒏𝒔𝒆𝒓𝒕+𝑋𝑑′′+𝑋𝑡+𝑋𝑒𝑞
New Idea:
Using an impedance pre-insertion to reduce the transients effects from synchronization
instead of adjusting ∆𝑉 through feedback.
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.
synchronization
requirements
∆Ipeak, ΔTe
must remain the
same level
IEEE or utility
criteria
Pre-established
Operating Region
Bulk Grid Generator,
Microgrid
( )gV pu
( )gf Hz
60.2
59.7
1.10.9 Pre-established Operating Region
( )sV pu
( )sf Hz
60.05
59.95
1.10.9
1 2
Z
Circuit Breaker
4. New Idea --- Open Loop Synchronization
Watch
∆V,∆θ,∆f
System ~
Feedback Control
Generator
No
Feedback
Watch ∆θ
Meet Criteria for ∆V,∆f?
Yes
∆θ<Criteria?
No
Close Synchronizing
Breaker
Yes
Close
Loop
Pre-established
Operating Region
Bulk Grid Generator,
Microgrid
( )gV pu
( )gf Hz
60.2
59.7
1.10.9 Pre-established Operating Region
( )sV pu
( )sf Hz
60.05
59.95
1.10.9
1 2
Z
Circuit Breaker
Each party operates within pre-
established operating region
(i.e. power quality limits)
Verify if V and f are within the
region at the breaker location
Can’t perform
Synchronization No
Yes
Watch ∆θ
∆θ<Criteria?
No
Close Synchronizing
Breaker
Yes
Bypass
Impedance
Open
Loop
5. Research Strategies
Problems Strategies
What is the acceptable
transient level?
How to select the impedance to
control switching transient?
Can the generator reach stable
condition?
Is the impedance bypass
transient acceptable?
• Use IEEE C50.12 criteria for generator
synchronization to establish acceptable
transients level.
• Use common utility operating limits for
voltage and frequency to establish open
loop criteria.
• Evaluate the bypass transients to
establish the number of steps or
impedance values for bypassing operation
• Establish a method or criterion to
determine the impact on stability
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): • |∆𝑰𝒑𝒆𝒂𝒌|=0.537 pu for stator current transient
• ∆𝑻𝒆=𝑻𝒆𝒎𝒂𝒙 − 𝑻𝒆𝒔𝒔 =0.628-0.056=0.572pu
6. Solutions – Acceptable transient level
0 0.5 1 1.5
0
0.5
1
Time (s)
Ele
ctr
om
agnetic T
orq
ue T
e (
pu)
0 0.5 1 1.5-1
-0.5
0
0.5
1
Time (s)
Sta
tor
Cur
rent
(pu
)
• Each party is expected to operate within established limits that meet the power
quality requirements of respective systems, as illustrated below:
• 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.
Vmin~Vmax (pu) fmin~fmax (Hz)
Micro-grid (bus 1) 0.9~1.1 59.7~60.2
System (bus 2) 0.9~1.1 59.95~60.05
Bulk Grid Generator,
Microgrid
1 2
6. Solutions – Impedance selection
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.
6. Solutions – Impedance selection
Research Method Step 1 (Worst case synchronization scenarios):
V1 (pu) V2 (pu) f1 (Hz) f2 (Hz) ∆θ=θ1-θ2 (deg)
case1 1.05 1 60.067 60 10
case2 1.1 0.9 60.2 59.95 10
case3 1.1 0.9 59.7 60.05 10
case4 0.9 1.1 60.2 59.95 10
case5 0.9 1.1 59.7 60.05 10
• 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.
Table 1: Synchronization Scenarios
1V
1f
60.2Hz
59.7Hz
1.1pu0.9pu2V
2f
60.05Hz
59.95Hz
1.1pu0.9pu
4 2
35
3 5
2 4
11
6. Solutions – Impedance selection
Research Method Step 2 (Worst case transients evaluation):
System under study:
15 miles 15 miles
25/4.16kVYg/Yg
SGSGSUB
25kV
346MVA
CB 6.6MVA
2.0MW
0.65MVAr2.0MW
0.65MVAr
2.0MW
0.65MVAr
V1,f1V2,f2
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 2.
0.00
0.10
0.20
0.30
0.40
0.50
0.60
0.70
0.80
0.90
case1 case2 case3 case4 case5
Torq
ue a
nd C
urr
ent
Devia
tion (
pu)
Te Ipeak
case2 1.1 0.9 60.2 59.95 10 Fig: Torque and current peak deviations when not
controlled by impedance insertion.
6. Solutions – Impedance selection
Research Method Step 3 (Impedance Design Procedure to Reduce Worst Case
Current Transient):
• Impedance Z is determined by analytical solution. The accuracy of the analytical
solution is verified by numerous transient simulations.
Case Study
File (reference case)
Case Study
File (worst case)
Establish V1,V2,f1,f2 and
∆θ across open breaker
(Initialize by loadflow)
Establish V1,V2,f1,f2 and
∆θ across open breaker
(Initialize by loadflow)
Calculation
Acceptable transient
level (I & Te)Calculation
1 2 1 2( , , , , , )acceptableZ f I V V f f
/
/
/
( ) sin( ) sin( )
( ) sin( ) sin( )
( ) sin( ) sin( )
Rt LAsyncA A A
eq
Rt LBsyncB B B
eq
Rt LCsyncC C C
eq
VI t wt e
Z
VI t wt e
Z
VI t wt e
Z
6. Solutions – Impedance selection
Analytical method for determination of Impedance |Z|
Following analytical equations were derived based on the transient circuit of superposition: For simplicity, assuming f1=f2 (same frequency)
Micro-grid
Generators Bulk Grid
Superposition
Across Breaker
V1, f1 V2, f2
1 2A B cV V V V V
1 2( )A V V 1tan ( / )wL R
• 𝑍𝑒𝑞 is the total equivalent series
impedance seen by the breaker.
• 𝑍𝑖𝑛𝑠𝑒𝑟𝑡𝑖𝑜𝑛 is determined by subtracting
all other system equivalent impedances
such as transformer, line, and generator
sub-transient reactance.
Where:
1 2( , , , )insertion acceptableZ f I V V
6. Solutions – Impedance selection
Analytical & Simulation results for determination of Impedance |Z|
0.05 0.06 0.07 0.08 0.09 0.1 0.11 0.12-2
-1.5
-1
-0.5
0
0.5
1
1.5
2
Time (s)
Sta
tor
Cur
rent
(pu
)
Phase A (simulation)
Phase A (Analytical)
0 0.1 0.2 0.3 0.4 0.5 0.60
0.2
0.4
0.6
0.8
1
Impedance Insertion Value (pu)
Sta
tor
Curr
ent
Devia
tion (
pu)
Simulation (case 2)
Analytical (case 2)
Reference caseZ=0.23pu
0.00
0.10
0.20
0.30
0.40
0.50
0.60
0.70
case1 case2 case3 case4 case5
Torq
ue a
nd C
urr
ent
Devia
tion
(pu)
Te Ipeak
Z Insertion=0.23pu
• 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.
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.
7. Bypass Transients
Bypass Transient Evaluation Method:
• 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.
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 𝐼𝑏𝑦𝑝𝑎𝑠𝑠 ∝ ∆𝑉 .
3. Determine and verify that whether if the worst bypass transient is below the
allowable limit.
7. Bypass Transients
Evaluation Step 1 (Evaluate Steady state P&Q Imbalance):
-0.25 -0.2 -0.15 -0.1 -0.05 0 0.05 0.1 0.15 0.2 0.25
-0.5
-0.4
-0.3
-0.2
-0.1
0
0.1
0.2
0.3
0.4
0.5
Active Power Imbalance (pu)
Reactive P
ow
er
Imbala
nce (
pu)
Z=0.23puZ=0.23pu1
2
3
4
• Real and reactive power imbalance is mainly due to a frequency difference and
voltage magnitude difference prior to synchronization. (∆𝑓 → ∆𝑃𝑚, ∆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.
• Segment 1-3 and 2-4 is obtained by fixing V1 and V2
but vary f1 (59.7-60.2) and f2 (60.05-59.95)
• Segment 1-2 and 3-4 is obtained by fixing f1 and f2 but
vary V1 (1.1-0.9) and V2 (0.9-1.1)
7. Bypass Transients
Evaluation Step 2 (Evaluate worst bypass scenario):
-0.25 -0.2 -0.15 -0.1 -0.05 0 0.05 0.1 0.15 0.2 0.25
-0.5
-0.4
-0.3
-0.2
-0.1
0
0.1
0.2
0.3
0.4
0.5
Active Power Imbalance (pu)
Reactive P
ow
er
Imbala
nce (
pu)
Z=0.23puZ=0.23pu1
2
3
4
• Since the ∆𝑉 across the impedance is dependent on |S|= 𝑃2 + 𝑄2, 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.
7. Bypass Transients
Evaluation Step 2 (Evaluate worst bypass scenario):
Micro-grid
Generators Z Insertion
BRK2
Bulk GridBRK1
1 1V 2 2V
V1 (pu) V2 (pu) f1 (Hz) f2 (Hz)
Case1 1.1 0.9 59.7 60.05
Case2 0.9 1.1 59.7 60.05
Case3 1.1 0.9 60.2 59.95
Case4 0.9 1.1 60.2 59.95
Impedance Switching (BRK1
Closes)
Real Power (pu) Reactive Power (pu) |S| (pu) ∆𝑽 𝒐𝒗𝒆𝒓 𝒁 (𝒑𝒖)
Case1 -0.068 0.446 0.451 0.1031
Case2 -0.214 -0.354 0.413 0.0946
Case3 0.128 0.377 0.398 0.0918
Case4 -0.024 -0.424 0.424 0.0982
Determine largest voltage
difference across impedance
(∆𝑉) (by power flow)
Worst bypass scenario is Case 1
-0.25 -0.2 -0.15 -0.1 -0.05 0 0.05 0.1 0.15 0.2 0.25
-0.5
-0.4
-0.3
-0.2
-0.1
0
0.1
0.2
0.3
0.4
0.5
Active Power Imbalance (pu)
Reactive P
ow
er
Imbala
nce (
pu)
Z=0.23puZ=0.23pu1
2
3
4
7. Bypass Transients
Evaluation Step 3 (Verify worst case bypass transient is within allowable limits):
0 5 10 15-2
-1.5
-1
-0.5
0
0.5
1
1.5
2
Time (s)
Sta
tor
Cur
rent
(pu
)
0 5 10 150
0.5
1
1.5
2
Time (s)
Ele
ctric
Tor
que
Te (p
u)
Impedance
switching Impedance bypass
Impedance
switching
Impedance bypass
• 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.
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
8. Transient Stability Assessment
Micro-grid
System
sys sysV
th
th
V
Z
0eP
Impedance
Switching
Equivalent Machine
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=𝑃𝑒𝑠𝑠=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.
0 0.2 0.4 0.6 0.8 1 1.2 1.4 1.6 1.8 2
Time (s)
Rot
or D
evia
tion
0 0.2 0.4 0.6 0.8 1 1.2 1.4 1.6 1.8 2
Time (s)
Rot
or F
requ
ency
(Hz)
Wsyn
o max
min
ss
In practice ,due to dynamics of field and
damping winding, the electromechanical
oscillation is damped and stabilizedWr
max min
8. Transient Stability Assessment
-90 0 90 180
Power Angle (deg)
Pow
er
Tra
nsfe
r P
e
o
max o
min o
max
th sys
eq
V VP
X
Initial Angle difference at across breaker
Rotor angle starts increasing due to higher micro-grid frequency
than system frequency
Begin
Synchronization
(Breaker closed)
Impedance Switching Impact on Transient Stability (Power Angle Relationship):
2𝐻
𝜔𝑠𝑦𝑛
𝑑2𝛿(𝑡)
𝑑𝑡2= 𝑃𝑚𝑝.𝑢 − 𝑃𝑒𝑝.𝑢
𝐻
𝜔𝑠𝑦𝑛
𝑑𝛿
𝑑𝑡
2
𝛿𝑚𝑎𝑥𝛿0
= (𝑃𝑚𝑝.𝑢 − 𝑃𝑒𝑝.𝑢)𝑑𝛿𝛿𝑚𝑎𝑥
𝛿0
𝛿max = 𝑐𝑜𝑠−1 cos(𝛿𝑜) −
𝐻
𝑊𝑠𝑦𝑛2𝜋 ∙ 𝑓𝑔𝑒𝑛 − 𝑓𝑠𝑦𝑠
2∙𝑋𝑡ℎ + 𝑋𝑖𝑛𝑠𝑒𝑟𝑡 + 𝑋𝑠𝑦𝑠
𝑉𝑡ℎ ∙ 𝑉𝑠
8. Transient Stability Assessment Worst case ∆δ_max due to Impedance Switching (with constant Ef):
Cases F1 (Micro-grid Frequency)
Hz
F2 (System Frequency)
Hz
V1
(pu)
V2
(pu)
∆θ=𝜽𝟏 − 𝜽𝟐
(Deg)
1 60.2 59.95 0.9 0.9 +10
2 60.2 59.95 0.9 0.9 -10
3 59.7 60.05 0.9 0.9 +10
4 59.7 60.05 0.9 0.9 -10
Worst case
With Constant Ef
• 4 cases are worth to consider to investigate the worst case ∆δ based on power quality limits.
22.8 23.7
27.0 27.8
0.0
5.0
10.0
15.0
20.0
25.0
30.0
case1 case2 case3 case4
∆δ m
ax (
deg)
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= - 0.35Hz, which the speed differential
represents the initial kinetic energy offset in the
rotor.
8. Transient Stability Assessment Worst case ∆δ_max due to Impedance Switching (with Excitation control AVR):
Cases F1 (Micro-grid Frequency)
Hz
F2 (System Frequency)
Hz
V1
(pu)
V2
(pu)
∆θ=𝜽𝟏 − 𝜽𝟐
(Deg)
1 59.7 60.05 0.9 0.9 -10
2 59.7 60.05 1.1 0.9 -10
3 59.7 60.05 0.9 1.1 -10
Worst case
With AVR
• 3 cases are worth to consider to investigate the worst case ∆δ based on power quality limits and AVR control
Fig: Impedance used equals 0.23pu, with Micro-grid
loading level= 85%.
27.8 26.1
17.7
27.3
19.8
36.4
0.0
5.0
10.0
15.0
20.0
25.0
30.0
35.0
40.0
case1 case2 case3
∆δ m
ax (
deg)
∆δ max (const Ef) ∆δ max (AVR)
• 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
8. Transient Stability Assessment Sensitivity study of Micro-grid Loading level and Machine Inertia effects on ∆δ_max:
0 10% 20% 30% 40% 50% 60% 70% 80%
26
28
30
32
34
36
38
Percentage Loading of Micro-grid
Max t
ransie
nt
Roto
r D
evia
tion (
deg)
Z=0.23pu
Z=0.3pu
Z=0.4pu
• 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.
Fig: Loading effects for case3 synchronizing
condition with AVR control
0 10% 20% 30% 40% 50% 60% 70% 80%20
25
30
35
40
45
50
Percentage of Micro-grid Loading Level
Max T
ransie
nt
Roto
r A
ngle
Devia
tion (
Deg)
H=1.26
H=2.52
H=5.04
• 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.
Fig: Sensitivity Study of the effect of Machine Inertia
(H) on transient stability, Z=0.23pu, case 3
8. Transient Stability Assessment Impedance Bypass Impacts on Transient Stability:
-90 0 90 180
Power Angle (deg)
Pow
er
Tra
nsfe
r P
e
Pmax increased
due to a decreased
in Zeq
ssPe
Micro-grid
System
sys sysV
th
th
V
Z
ssPe
Bypass
Switching
Equivalent Machine
0 1 2 3 4 5 6 7 8-20
-15
-10
-5
0
5
10
Time (s)
Rot
or A
ngle
(Deg
)
Impedance Switching
Bypass
• 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 𝛿𝑜 ≪ 10° and ∆f=0.
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).