D2-01_34

Report
A Smart Grid Application for
Dynamic Reactive Power
Compensation
A presentation by
G. Vamsi Krishna Kartheek
PRDC, Bangalore
Co-Author
SVN Jithin Sunder
BHEL, Hyderabad
1
Requirement of Automatic Coordinated Control
• Modern power system are distributed over a wide geographical region.
• Voltage levels are 33kV, 132kV, 220kV, 400kV, 765kV and even 1200kV.
• Both conventional and non-conventional sources are present.
• Voltage controls are like AVR, Online tap change transformers, FACTS,
HVDC, Switchable capacitors and reactors, etc.
• All these controls to be coordinated through centralized control to achieve
optimization at higher level.
• Automation is to implement effective control in real time.
2
Steps to Implement Automatic Coordinated Control
• Network operating condition to be monitored
• Network operating state to be visualized
• Higher level control from a centralized control center
• Complete system automation
• Effective ICT
3
Technologies to be Effectively Deployed and Exploited
• Network operating condition monitoring
– Measuring devices to measure voltages, real power, reactive powers
– PMU technologies to measure voltage phase angle at all substations
• Network operating state visualization and Higher level control from a
centralized control center
– PRM control system for visualization and control in real time to
optimize the reactive power dispatch from time to time.
– Additionally various system stability analysis algorithms (non real
time) can run in back ground for visualization and analysis of operator.
4
Technologies to be Effectively Deployed and Exploited
• Automation of complete reactive power control
– Thyristor switched reactors in place of fixed shunt reactors where ever
possible.
– Dynamic reactive power support devices like SVC, STATCOM, CSR,
etc.
– Relay protection and circuit breaker control be centralized in all
substations and be monitorable/controllable from control center.
– Complete automation of substations where reactive power control is
present.
– Any substation/power plant monitoring and control system will be
centralized in itself and controllable from control center.
5
Technologies to be Effectively Deployed and Exploited
• Effective ICT
– Good communication channels for communication between control
centers and entire network.
– Full-fledged SCADA system with hierarchal control system.
– Substation wise control be primary level control
– PRM control system at control center will be secondary level control.
– State of art technology hardware and software.
6
Phasor Relativity based Mathematical Control System
• The PRM control system will not predict any voltage collapse.
• The control system will always try to bind the system operation within the
optimum region of operation through optimum reactive power dispatch.
• So this will enhance the voltage stability from time to time.
• The computations will be from the local measurements.
• We are proposing PRM control system for online real time control based on
the studies performed.
7
WAMS Architecture proposed by [2]
Dotted Line Indicates
Data Flow
8
WAMS Architecture with PRM Control System
Dotted Line Indicates
Data Flow
Solid Line Indicates
Control Flow
Secondary & Highest Level Control
Primary Level Control
9
WAMS Architecture with PRM Control System
• Any disturbance will lead to change in operating state.
• New optimum reactive power dispatch will be generated for the new state.
• Incase of system islanding each island will operate as separate region.
• So the respective PRM control system in the island will be the central
control.
• Any time the controller at NLDC will be the supreme.
• Effective reactive power management helps to neutralize the post
disturbance uncertainties.
• Ultimately helps in mitigating blackout.
• No alarm will be generated to indicate voltage collapse.
• Alarms can be generated to indicate the exhausted reserves.
10
Types of Controls
Control Stations
Generating Plant
Types of Controllers
AVR, Governor, Transformer tap control, bus/line
switchable reactors (if any available)
EHV/UHV substations
Transformer
tap
control,
Switchable
bus/line
reactors, switchable capacitors, FACTS
HVDC substation
Converter control, Inverter control, switchable
capacitors, switchable reactors
Non-Conventional
Sources
Energy Switchable
capacitors,
switchable
reactors,
transformer tap control, FACTS
11
Case Studies Performed
• Two case studies are performed, model analysis and time domain
simulation.
• All devices are assumed to be centrally controlled.
• System operating state data comes from SCADA using PMU in WAMS
• In Model analysis performing load flow, the same data is assumed to be
reaching the PRM control system.
• The simulation demonstrates the performance of PRM control system for
functional behavior of the system.
• In the time domain simulation also similar consideration is assumed.
12
Equivalent South Indian Grid Model (EHV 24 Bus
System)
13
Case Study 1
• Model analysis is performed for three cases. The cases are as below.
– Case(1):- This case is with fixed shunt reactors and no control in the
system.
– Case(2):- This case is with fixed shunt reactors but PRM control system
is implemented with controls limited to generators, tap change
transformer and switched shunt capacitors.
– Case(3):- In this case along with all the controllers in the case(2) CSR
is also installed in the PRM control system.
14
Studies Performed on the EHV 24 Bus System
• Load is varied from 40% of the base load to the maximum permissible limit
in each case.
• For every 10% of load variation a snapshot is collected.
• Control calculations are performed manually according to the algorithm.
• The voltages are plotted for the three cases for all the snapshots.
• Voltage stability indices plot and loss plot are drawn separately for all the
three cases.
• MATPOWER and PSAT software are used.
15
Results of the Cases(1)
Maximum Network
Loading Limit
Is 100% of Base Load
Network Voltages are
between 0.82-1.10 p.u.
Voltage profile(p.u.) Vs percentage of base load
16
Results of the Cases(2)
Maximum Network
Loading Limit
Is 110% of Base Load
Network Voltages are
between 0.84-1.05 p.u.
Voltage profile(p.u.) Vs percentage of base load
17
Results of the Cases(3)
Maximum Network
Loading Limit
Is 145% of Base Load
Network Voltages are between
0.95-1.05 p.u. upto 140% of Base Load
Voltage profile(p.u.) Vs percentage of base load
18
Eigen Value Analysis for Voltage Stability of the Three
Cases
Most predominant Eigen value (distance from Y axia) Vs percentage of
base load
19
Real Power Losses of the Three Cases
Real Power losses(MW) Vs percentage of base load
20
Comparison of Three Cases
No Control Case
Power Transmission 100%
Capacity
Control without
CSR
115%
This limit can be
extended to 180%
with installed shunt
capacitors
Control with CSR
145%
Voltage Limits in
p.u.
0.82-1.10
0.84-1.05
Types of Controls
No Controls
AVG, Onload
Tapchanger, Shunt
Capacitors
0.91-1.05
(0.95-1.05 upto
140%)
AVG, Onload
Tapchanger, Shunt
Capacitors, CSR.
Real power loss at
rated full load
70MW
60MW
55MW
21
Case Study of Stability Maintenance under Disturbance
Condition
• The studies are performed for two cases.
• The cases are
• Case(A):- The reactors are fixed reactors.
• Case(B):- The reactors are switched reactors and PRM control system is
implemented.
• Branch between buses 23-24 is tripped at 10s.
• Voltages, rotor angles and powers are plotted for the two cases.
22
Voltage and rotor angle plots of two cases
Case(B)
1.05
1.05
1
1
0.95
0.95
0.9
0.9
0.85
0.85
Voltages (V)
Voltage (V)
Case(A)
0.8
0.75
0.8
0.75
0.7
0.7
0.65
0.65
0.6
0.6
0.55
0
20
40
60
80
0.55
100
Time (s)
20
40
60
80
100
Time (s)
0.6
 Syn 1
0.4
 Syn 1
0.4
 Syn 2
0.2
 Syn 2
0.2
 Syn 3
0
 Syn 3
0
Rotor Angle
Rotor Angle
0.6
0
 Syn 4
-0.2
-0.2
-0.4
-0.4
-0.6
-0.6
-0.8
-0.8
-1
0
20
40
60
Time (s)
80
100
 Syn 4
-1
0
20
40
60
Time (s)
80
23
100
Explanation to the Case Study
• The network with reactors
connected wont satisfy n-1
contingency means in Alert
state.
• When any fault occurs it
goes to emergency or
extremis case.
• Network with reactors disconnected satisfies n-1 contingency so its in normal
state.
• When any fault occurs it goes to alert state.
24
Explanation to the Case Study
• When the reactors are suddenly switched the system that’s in alert state will
stay in alert state for some more time.
• This time gap may be of order of 20s to 5mins.
• Some control action should taken to bring the system back to normal state.
• If not again blackout may occur or load shedding is to be performed.
• The operator or the control system has to make advantage of this time gap
to secure the system.
25
Significance of PRM Control System and CSR
• System security will be improved with increased reactive power reserve.
• Reduction in dynamic over voltage limit as its no more required to limit the
reactive compensation to 60%.
• The faster response of CSR (10ms) will be primary control and PRM
control system will be secondary control with response time of 10-20s.
• System security is improved with CSR. (as system satisfies n-1
contingency)
• Coordinated control can avoid blackouts.
• Reduces the installation cost and the maintenance cost in a significant
manner.
26
Intelligent Control Actions that can Save System from
Collapse
• Intelligent switching of line, bus reactors, shunt capacitors and FACTS
devices
• Using optimum tap controls
• Intelligent and controlled switching of line circuit breakers
• Optimally setting the generator terminal voltage
• Optimal load dispatch under critical situations
27
Conclusion & Future Work
• In the studies performed, the local controls are not considered as it is
difficult to simulate local automatic control.
• However the future work is to simulate local automatic control at each
substation and centralized control in RTDS.
• PMUs to be present at main substations and where control is available.
• WAMS system present at control centers.
28
Thank you
Questions & Discussions
29

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