Mini-Course on Future Electric Grids Part 2

Mini-Course on Future Electric Grids
Part 2 of 2

Dirk Van Hertem — Dirk.VanHertem@ieee.org

Electric power systems
EKC2 , Controllable power systems
Electrical engineering department
Royal Institute of Technology, Sweden

March 8, 2010

K.U.Leuven (Belgium) KTH, Stockholm (Sweden)

Dirk Van Hertem (Electric Power Systems, KTH) Mini-course on Future Electric Grids (2/2) 8/03/2010 1 / 47

Introduction Course overview

Who am I?

Master in engineering from KHK Geel, Belgium
Master of science in engineering from K.U.Leuven, Belgium
PhD in engineering from K.U.Leuven, Belgium
Currently Post-Doc researcher at the Royal Institute of Technology,
Stockholm, Sweden
Program manager controllable power systems group of the Swedish
center of excellence for electric power systems (EKC2 )
Active member of both IEEE and Cigré



Course overview and objectives

Overview Part 1
New situation in the power system
1 Liberalization of the market
2 Increased penetration of smaller, variable energy sources
3 No single authority in Europe
4 Lacking investments in the transmission system



Course overview and objectives

Overview Part 2
International coordination in the power system
How this coordination is evolving (Coreso)
Power ﬂow controllers
Coordination and power ﬂow controllers
The future “supergrid”. . .
. . . and the road towards it



What it is about and what not

Not the grid of 2050
Main focus is Europe
Not about smart grids (or not speciﬁcally)
About transmission and not distribution
Mainly from a grid operator point of view



1 Introduction
Course overview
2 Coordination in the power system
Situation sketch
Information exchange between TSOs
Steps towards increased coordination: Coreso example
3 Power ﬂow controllers
Introduction
Controlling PFC in an international context
Example: Losses in a grid
Need for coordination
How to coordinate?
4 Supergrids
A supergrid?
Technology requirements for the supergrid
Controlling the supergrid
Techno-Economic approach to a supergrid
5 Conclusions


Coordination in the power system

1 Introduction
Course overview
Situation sketch
Introduction
How to coordinate?
4 Supergrids
A supergrid?
5 Conclusions


Coordination in the power system Situation sketch

Power system control before liberalization

Vertically integrated companies
Generator company and grid operator are one company
Power system operator controls the power system:
Unit dispatch is done by system operators
Topology changes: Line switching
Reactive power: capacitor switching and VAr control of generators
International/-zonal redispatch (at cost)
All generation is centrally controlled


Coordination in the power system Situation sketch

Now: different involved parties

Unbundling separated generator, transmission, distribution and
suppliers
Power exchanges were introduced
Renewables were introduced
Generation no longer directly controlled by transmission system
operator
Operator controls the transmission system:
Unit dispatch can be requested by system operators at a cost
Topology changes: Line switching
Reactive power: capacitor switching, but VAr control of generators?
International/-zonal redispatch (at cost)
A significant increase of power flow controlling devices is noticed
Less stable pattern due to market: high volatility
Need for firm capacity for the market participants
⇒ Higher need for control with less “free” means


Coordination in the power system Information exchange between TSOs

Interconnected power system: information exchange

The different zones are interconnected (synchronous zones)
Operated independently
International market operation
Operation of the system effects the system cross-border
Information is exchanged:
Grid status (important outages)
Day-ahead congestion forecasts
Expected available capacities
Any emergency with possible effects outside of the zone
Not everything is exchanged
Not all the generation data (aggregated)
Grid data on a “need-to-know” basis
Quite good working system



DACF: Day-ahead congestion forecasts

Procedure
Estimated zonal grid (cut at the borders) is provided
Together with expected aggregated load/generation
patterns
The planned state of devices such as on-load tap
changers and capacitors is provided
Sum of generation, load and losses equals the
planned exchange
Exchange is set in the interconnections (X-nodes)
Reactive power is set to a sensible amount
Local load flow is run
Data file is uploaded and merged
Merged load flow is run and returned to TSO
In case of congestion: TSOs negotiate appropriate
actions



Still some problems

Unexpected loop ﬂows
Uncertainty in the system remains high
Black-outs or near black-outs due to lack off coordination and or
communication
August 2003: Italian black-out:
Stopping pumped hydro (or reverse) might have helped
Miscommunication was one of the main problems
November 2006: UCTE near black-out
Communication between operators failed
Sequence of events that could have been avoided



Limitations in cooperation

Unforeseen events may occur
Not everything is known
With higher uncertainties and less control options, the system operator
has limited tools available
Some problems might be easily solved in another zone instead of costly
local actions
System-wide security assessments are not performed/updated during
the day


Coordination in the power system Steps towards increased coordination: Coreso example


What is Coreso?
The ﬁrst Regional Technical Coordination Service Center (created Dec.
2008, in operation since Feb. 2009)
Independent company, located in Brussels (www.coreso.eu)
Shareholders are TSOs (founders Elia and RTE, and National grid),
open to others
Coreso does not operate the grid, but acts as a coordinated supervision
for its members


Coordination in the power system Steps towards increased coordination: Coreso example

Service provider for TSOs
Type of services:
Pro-active assessment of the safety level of the network (day ahead and
close to real time forecast)
Proposing to the TSOs the implementation of optimized coordinated
actions to master these risks
Relaying signiﬁcant information and coordinating the agreement on
remedial actions
Contributing to ex-post analysis and experience reviews of signiﬁcant
operating events for the appropriate area
Providing D-2 capacity forecast
Focus on:
Supra national view on the network
Cross-border impacts between TSOs
Improved regional integration of renewable energy
Area of interest: participating TSOs
Security analysis extends to CWE (Benelux, France and Germany)


Power ﬂow controllers

1 Introduction
Course overview
Situation sketch
Introduction
How to coordinate?
4 Supergrids
A supergrid?
5 Conclusions


Power flow controllers Introduction

What is power flow control

Bending the laws of Kirchhoff
In normal systems, power flows according to the laws of Kirchhoff
Power flows in meshed networks depend on the relative impedance of
the lines
Using power flow controlling devices, these flows can be influenced
Simplified: PFC work as a valve
Overloaded lines can be relieved
System can be adjusted to the situation: day-night, summer-winter,
import-export, maintenance situations,. . .



Power flow control
Power flow equations for a simple transmission line:
|US | · |UR |
Active power: PR = X · sin (δ)
|US | · |UR | | UR | 2
Reactive power: QR = X · cos (δ) − X
Receiving end power can be altered through voltage,
impedance and angle
Different technologies exist: mechanically switched,
 ·I ·X
thyristor based and fast switches
UR
Subset of FACTS (flexible AC transmission systems)

IS X IR

US δ

US UR I



Power ﬂow control
|US | · |UR |
|US | · |UR | | UR | 2
Reactive power: QR = X · cos (δ) − X Voltage
UR
impedance and angle

IS X IR
US

US UR



Power ﬂow control
|US | · |UR |
|US | · |UR | | UR | 2
Receiving end power can be altered through voltage, Impedance
impedance and angle UR


IS X IR
US

I
US UR



Power ﬂow control
|US | · |UR |
|US | · |UR | | UR | 2
impedance and angle
Different technologies exist: mechanically switched, UR
Angle

IS X IR
US

US UR



PFC devices: examples

Phase shifting transformer
US UR
Mechanically switched device
Basic principle of a transformer ∆U1 = 2 · k · UM23

k · UM23
How it works: Injects a part of UR 1 US1
UM3 UM2 UM1
UM1
the line voltage of opposing
k · UM23
phases in series with the phase
UM31 UM12
voltage to create an angle
difference
Different types: direct/indirect UM23 UM23

and symmetrical/asymmetrical UM3 UM2

Cheap, robust, efﬁcient and
slow



PFC devices: examples
TSSC/TCSC: Thyristor switched/controlled
TSSC ↔ TCSC series capacitor
Compensate the natural series inductance of
transmission lines
Especially used for longer lines
Possible to use for dynamic power system
oscillation damping



HVDC: High Voltage Direct Current

LCC HVDC
Line commutated converter HVDC
Exists for over 50 years
High ratings, relative low losses
Needs a strong AC grid to connect to

1
0
1
0
DC reactor
1
0 1
0

AC ﬁlter 1
0
1
0
1
0 1
0
1 1
0 0
1
0
1
0
Y /Y
1
0
1
0 1
0 1
0 1
0
1
0
1
0
1
0 1
0
1111111111
0000000000
1
0
1
0
1 1
0 0 1
0
1
0
1
0
Y /∆
1
0 1
0

Converter DC ﬁlter
AC switchyard


A three phase converter consisting of three 3-level phase units is illustrated in Figure 4.3. The single-
As phase output voltage waveform, relative duration of the positive (and negative) output voltage with
indicated in the figure, the assuming fundamental frequency switching,Power ﬂow controllers
is also shown in Figure Introduction
respect to the duration of thedc terminals to is a function of or centre-tapped dc source. As seen,
4.3. The converter has three zero output connect to a split control parameter �, which defines the
conduction interval of thevalves used as in the 2-level phase unit, and additional diodes are required to
there are twice as many top upper, and the bottom lower valves. The magnitude of the fundamental
connect to the dc supply centre-tap, which is the reference zero potential. However, with identical
frequency component of the output voltage total dc supply the phase unitdoubled so that the parameter �.
valve terminal-to-terminal voltage rating, the produced by voltage can be is a function of output
When � equals zero degreessame. maximum, while at � equals 90 degrees it is zero. Thus, one
voltage per valve remains the it is
advantage of the 3-level phase unit is that it has an internal capability to control the magnitude of the
output voltage without changing the number of valve switchings per cycle.
+
The operating advantages of the 3-level phase unit can only be fully realised with some increase in
circuit complexity, as well as more rigorous requirements for managing the proper operation of the
Ud
converter circuit. These requirements are related to executing the current transfers (commutation)
between the four (physically large) valves, with well-constrained voltage overshoot, while maintaining
the required di/dt and dv/dt for the semiconductors without excessive losses. +Ud
UL1
Neutral
(mid-) point UL2
An additional requirement is to accommodate the increased ac ripple current with a generally high
UL3
triplen harmonic content flowing through the mid-point of the dc supply. This may necessitate the use
-Ud
�
of a larger dc storage capacitor or the employment of other means to minimise the fluctuation of the
mid-point voltage. However, once these problems are solved, the 3-level phase unit provides a useful VSC HVDC
Ud
building block to structure high power converters, particularly when rapid ac voltage control is needed.

-
The conduction periods for the inner and the outer valves is different, and therefore it is possible to use
Voltage source converter
two different designs of a VSC valve for the two positions.
Figure 4.3: Three-phase 3-level NPC converter and associated ac voltage waveform for one phase
By switching the valves more frequently, it is possible to eliminate more harmonics. A typical PWM
Quite new
switched waveform, using a carrier based control method with a frequency of 21 times fundamental
frequency,waveform shown in the 4.4. For the purpose of voltage, assuming fundamental frequency been
The ac is given in Figure figure is the phase-to-neutral this illustration, the dc capacitor has Fast switching (PWM)
Figure: Scheme of a 3-level 3-phase VSC
assumed to have anvalves. The neutral voltageno dc voltage ripple).
switching of the infinite capacitance (i.e., is the voltage at the midpoint of the dc capacitor. As
illustrated in Figure 4.3, the output voltage of the 3-level phase unit can be positive, negative, or zero.
Positive output is produced by gating on both upper valves in the phase unit, while negative output is
produced by gating on both lower valves. Zero output is produced when the upper and lower middle
Highly dynamic
1
valves, connecting the centre tap of the dc supply via the two diodes to the output, are gated on. At
zero output, positive current is conducted by the upper-middle controllable device and the upper centre- Makes its own rotating ﬁeld
Line-to-neutral voltage (pu)

tap diode, and negative current by the lower-middle controllable and the lower centre-tap diode.

0 Relative high losses
4-4 Only two manufactures (ABB and
1

0 90 180 270 360
Siemens)
Degree

Figure 4.4 Single-phase ac voltage output for 3-level NPC converter with PWM switching at 21 times (→ Source: Cigré Tech. Rep. 269)
fundamental frequency

Figure: Voltage waveform of a 3-level 3-phase
4.2.4 Multi-Level Neutral Point Clamped Converter
VSC with single phase output voltage
In order to further reduce the harmonic content of the ac output voltage, the basic 3-level phase unit can
be(fswitch a= 21 × 2n+1 phase unit (n=1,2,3,…) configuration. 2n dc supplies, provided by
extended to multi-level, fn )
2n dc storage capacitors (which are common to all three-phase units of a complete three-phase
converter),Van Hertem (Electric Power Systems, KTH)
Dirk are connected in series, providing 2n+1 discrete voltage levels. Mini-course onvalves are
Four times n Future Electric Grids (2/2) 8/03/2010 18 / 47



HVDC is a special power flow controller
Allows full, independent active power flow control
VSC HVDC also provides independent reactive power flow control
The ultimate power flow controller, yet not a true power flow controller

A B

HVDC as a single link between two independent networks, no possibility for
active power flow control (flow is equal to the imbalance in the zones)





HVDC as part of the meshed AC power system, HVDC can be operated as a
PFC, with a ﬂow independent on the rest of the system





A B

Two meshed networks are connected through multiple HVDC. HVDC can be
used as PFC when there is coordination



Power flow controlling devices: classification

AC Network controller

Conventional FACTS Devices
(Switched) (Fast, static)

R, L, C Thyristor Voltage Source
Transformer Valves Convertor (IGBT)

Switched Shunt Static VAr Controller Static Synchronous
Shunt devices Compensation: (SVC) Compensator
L and C Thyristor Controlled (STATCOM)
Reactors (TCR),. . .

Switched Series Thyristor Controlled Static Synchronous
Series devices Compensation: and Thyristor Switched Series Compensator
L and C Series Compensator (SSSC)
(TCSC and TSSC).

Phase Shifting Thyristor Controlled Unified Power Flow
Combined Transformer(PST) Phase Angle Controller (UPFC)
Series & Shunt Regulators (TCPST) VSC HVDC
LCC HVDC



Existing/planned power ﬂow controllers in the Benelux
Norned u
E
UK-Fr
Eu u Diele
Meeden '
1 HVDC interconnector UK-FR
Gronau 2 Meeden PSTs (2×)
BritNed
u Eu 3 Gronau PST

Zandvliet 4 Monceau PST

u
Eu Van Eyck 5 Norned HVDC
c u$
W
$
uy
ˆ 6 Van Eyck PSTs
Monceau
ˆ 7 Zandvliet PST
u

©
8 Diele
9 BritNed (2011?)

(source: UCTE)



Existing/planned power ﬂow controllers in the Benelux
Cobra and/or Norned 2
Norned u
E
UK-Fr 1 HVDC interconnector UK-FR
Eu u Diele
Meeden ' 2 Meeden PSTs (2×)
3 Gronau PST
Gronau 4 Monceau PST
BritNedu Eu 5 Norned HVDC

Zandvliet
6 Van Eyck PSTs
u NEMO u Eu Van Eyck
u Zandvliet PST
7
c u$
W
$
uy
ˆ 8 Diele
u u
Monceau
ˆ 9 BritNed (2011?)
BE-DE
u
©
10 NEMO (2013?)
11 Belgium Germany (?)
12 Cobra and/or Norned 2 (?)
Most are less than 10 years old

(source: UCTE)


Power flow controllers Controlling PFC in an international context

Control of PFC
Locally controlled
The investment is normally done by a TSOs
Therefore control is done by the TSO to fulfill his own objectives
Payed for by the local market participants,
so “revenues” should be returned to the local market as well
Optimal use of the transmission system
Minimum losses
Maximum security
Maximum transmission capacity

Effects are not local
Devices are mostly placed on the border
The effects of active power flow control can reach far into neighboring
systems
Some control actions are intended to influence “external” powers


Power flow controllers Controlling PFC in an international context

Multiple zones, multiple PFC
Load Load Load Load

A A A A

50 % 50 % 20 % 80 % -10 % 110 % 50 % 50 %

α β α α
B D B D B D B D

Gen Gen Gen Gen

C C C C

(A) (B) (C) (D)

Example of possible problems with power flow control in multiple zones
A: Generation in the south, load in the north, equal flow distribution
B: Zone B invest in a power flow controller: power flow is shifted
C: Overcompensation by B (following schedules, optimizing for zone B)
D: D also invests in a power flow controller: two investments, no advantage


Power ﬂow controllers Example: Losses in a grid

System losses with power ﬂow control
Higher losses in one line = higher system losses
0.1 pu R and 0.1 pu X in parallel
2 2 2
Ploss = R1 · I1 + R2 · I2 = R1 · I1
⇒ shift power to the line with X

R = 0.1 pu
I1

I2 111111
000000
111111
000000
111111
000000
111111
000000
111111
000000
X = 0.1 pu

A PFC can lower losses by pushing the current towards lines with lower
resistance
In case of a constant X /R ratio, the use of a PFC increases the overall
losses in the system
But also lowering local losses (while having higher system losses)
Example IEEE39-bus system as test grid


Example: Three zone system, two PFC
Generators are circles, load busses are square
Green lines are PFC



Losses within multiple zones, two PST

20

Contour plot of the losses
in the 3 zones
Phase shifter 2 (degree)

10

0

−10

−20

−25 −20 −15 −10 −5 0 5 10 15 20 25
Losses in the 3 zones
dependent on the settings of the two PSTs.




20

d Contour plot of the losses
in the 3 zones

10 ‚
d
d Zone 1, Zone 2 and Zone

0 ‚
d ©
3: 3 optima

−10

−20

−25 −20 −15 −10 −5 0 5 10 15 20 25




20

in the 3 zones

10
Zone 1, Zone 2 and Zone
3: 3 optima
0
PST 1 is controlled by zone
2
−10

−20

−25 −20 −15 −10 −5 0 5 10 15 20 25




20

in the 3 zones

10
3: 3 optima
0
2
−10 PST 2 is controlled by zone
1 or 3 (interconnector)
(example: 1)
−20

−25 −20 −15 −10 −5 0 5 10 15 20 25




20

in the 3 zones

10
3: 3 optima
0
2
−10 PST 2 is controlled by zone
1 or 3 (interconnector)
(example: 1)
−20
Initial control zone is “bad”
for zone 2
−25 −20 −15 −10 −5 0 5 10 15 20 25




Suboptimal optimization
3 zones, 3 optimal phase shifter settings
Phase shifters are not mutually controlled or coordinated
Good for one can be bad for another
Nash-equilibrium?
Best solution for the system is not achieved
Angle (PST1, PST2)
Losses (MW) (−13◦ ,0◦ ) (−5◦ ,9◦ ) (0◦ ,2◦ ) (−5◦ ,6◦ )
Zone 1 11.4 13.2 12.3 12.4
Zone 2 11.6 8.72 9.8 8.91
Zone 3 12.0 9.18 9.17 9.23
Total 35.0 31.1 31.3 30.6


Power ﬂow controllers Need for coordination

Need for coordination. . .

Different objectives
Minimize local losses, not foreign
Maximize export capacity to “B”, not import from “C”
Objectives can be excluding
What is good for zone “A”, is not necessary good for “B”
And vice-versa
Global objective is generally not reached when there are multiple
objectives
TSOs are no competitors, but each has his own objective
Rather unwillingly obstructing other TSOs or grid users
PFC control has ﬁnancial repercussions
Communication is key


Power ﬂow controllers How to coordinate?

Possible control regimes of PFC for the European system

Local, single control objective
Every party on its own
Uncoordinated operation
PFC coordination in a market environment
Regional coordination
Full system coordination
New organization
Single ISO approach
Single TSO approach




Solving local problem
PFC coordination in a market environment (no coordination
Regional coordination needed)
New organization
Single ISO approach
Single TSO approach




Local objective
Do not take actions of
PFC coordination in a market environment neighbor into account
Regional coordination Coordinate only for
Full system coordination safety
New organization
Single ISO approach
Single TSO approach




Uncoordinated operation Optimize, knowing
neighboring systems
Different objectives
Nash-equilibrium
New organization
Single ISO approach
Single TSO approach




PFC control = money
Include in the market
mechanism?
Local, single control objective PFC and ﬂow based
market coupling?
Zone 1+2
New organization
Single ISO approach Zone 2
Single TSO approach
?
6 Zone 1




PFC inﬂuence is limited
in distance
Possibilities to
PFC coordination in a market environment implement in the current
Regional coordination framework
Full system coordination Coreso is taking ﬁrst
New organization steps
Single ISO approach
Single TSO approach




Every party on its own Optimize social welfare
Uncoordinated operation Additional organization:
difﬁcult
ISO: who will invest?
Full system coordination TSO: national assets will
have to merge
New organization
Single ISO approach
Single TSO approach




Every party on its own Optimize social welfare
Uncoordinated operation Additional organization:
difﬁcult
ISO: who will invest?
Regional coordination ⇒ most realistic ﬁrst step
Full system coordination TSO: national assets will
have to merge
New organization
Single ISO approach
Single TSO approach



Regulatory framework

Current framework
PFCs are generally left out of the regulations
UCTE operation handbook mentions PSTs as possible means of
guaranteeing security
No special required agreements exist to enforce PFC coordination

Proposed changes
For the TSOs/operators:
⇒ Increased communication
Future European regulation
PFCs and their effects should not be forgotten in forthcoming regulations
Aim for more coordination through effective regulations
Not only TSOs but also for regulators

First step towards further integration, and insufﬁcient on a long term


Supergrids

1 Introduction
Course overview
Situation sketch
Introduction
How to coordinate?
4 Supergrids
A supergrid?
5 Conclusions


Supergrids A supergrid?

A supergrid?

What is a supergrid?
A popular deﬁnition: a supergrid is an overlay grid connecting different
generation and load centers over larger distances
It serves as a backbone
Adds reliability and security of supply to the system
A grid offers redundancy
Sometimes also called “hypergrid”

New?
Recurring issue
Electric transmission started from 1 generator to several local loads
Grids became interconnected, at increasingly higher voltages
The 400 kV grid became the supergrid of the 50’s



A supergrid?

Early idea of a supergrid (after WW2)



A supergrid?

Early idea of a supergrid (after WW2)
Implemented as a 400 kV AC grid



Supergrid to connect remote renewable energy sources
There is plenty of renewable energy available
Solar from the Sahara, wind from the North Sea and hydro from Norway
to balance

(source: desertec)


Supergrid to connect remote renewable energy sources
There is plenty of renewable energy available
Solar from the Sahara, wind from the North Sea and hydro from Norway
to balance

±1 km between mills
(1/km2 )
take 10 MW/mill (future)
UCTE: 600 GW generation
Capacity factor 1/3
Required surface to replace
UCTE generation:
600 · 103 ×3
1×10
= 180 · 103 km2
square of 430 km × 430 km
or 100 km wide, 1800 km
long coastal track (Germany
has about 2300 km
coastline)


Supergrids: current “proposals”


Supergrids Technology requirements for the supergrid

Technology for the supergrid

Requirements
High power transfer capabilities
Long distances
High transmission efﬁciency
Cheap
Offshore connections
High reliability
Compatible with the current infrastructure



Potential technologies
Overhead lines AC connections
OHL has high power ratings
Allows long distances, but at high losses
No offshore connections
OHL are difﬁcult to get permissions
AC cables
Limited length and rating
Difﬁcult system operation
LCC HVDC (thyristor based)
Current source inverter
Parallel connecting of multiple terminals is troublesome
Series connection gives reliability problems
Cables are possible although limited capacity
VSC HVDC (Fast switches)
Voltage source converter: straightforward parallel connections
Converter ratings are limited (but rising)
Cables are possible although limited capacity
Weak grids are possible



Conclusion
⇒ No perfect solution.
VSC HVDC for offshore supergrid
AC OHL when possible?
For Europe, VSC HVDC seems most appropriate
AC system on shore is already quite strong
Many load centers are located relatively close to the sea



Ratings
}
LCC HVDC
OHL
UDC [kV ] 6400 MW
800

{
VSC HVDC
OHL
2000 MW

{
600
VSC/LCC HVDC
Oil ﬁlled cable
2000 MW

{
“Super”grid needs to be bigger
VSC/LCC HVDC
than existing 400 kV AC 400
MI cable 2000 MW

{
systems VSC HVDC
Existing AC: ≈ 2 GVA/circuit XLPE cable
1100 MW
200
⇒ 5 GW? – 10 GW?
New developments are needed,
especially if cables are used IDC [kA]
0
0 1 2 3 4

Figure: Current possible ratings for HVDC systems (UDC
refers here to the pole voltage, in a bipolar setup,
P = 2 · UDC · IDC ).



Standards

Similar to the AC system, standards are needed
Standard voltages
Once chosen, it is difﬁcult to change
What with the integration existing/upcoming lines?
Different manufacturers must be able to connect to the same DC
system (no vendor lock-in)
The control systems of different manufacturers/owners must operate
together and without detriment to the AC system



How should the grid look like?

DC Grid
Option 1
Multi-terminal without
redundancy
AC Grid DC and AC system form each
others redundancy
Injections and thus DC ﬂows
are controlled




Option 2
DC Grid Grid of point-to-point DC lines
Converter at both ends
Some lines in the AC grid are
replaced by DC lines
AC Grid
Full control
AC connections and therefore
AC protection devices
Many expensive and lossy
converters




Option 3
Meshed DC grid
DC Grid
Redundant lines
Only converters at interface
between AC and DC grid
AC Grid Reduced losses
DC ﬂows can not be directly
controlled
Cigré workgroup B4-52
considers only this a real DC
grid



Connecting to the existing AC system

The current AC system has not many infeed/withdrawal points for
> 5 GW
Reinforcements are needed in the existing AC system as well
The complete grid build-up/orientation might change
Originally from generation centers (near mines, mountains,. . . ) to load
centers
With supergrid: to from the nearest supergrid terminal (near the shore) to
inland load centers
Security
N-1 connection: Serious disturbance in the system when a terminal is
disconnected
1 or 2 connections per zone?
What rating and how many connections to smaller synchronous zones:
Ireland (7.8 GW installed capacity), Nordel (61 GW installed capacity),. . .



Protection

Current VSC HVDC protection
Interrupting DC currents is difﬁcult
AC protection is easy
⇒ Opening the AC system, disconnecting the complete DC circuit

PS

Figure: Protection system (PS) in existing VSC HVDC systems

NOT USEFUL for supergrid



Protection
Supergrid protection boundaries
Fault causes rapidly changing currents in all lines
Selectivity: Only the affected DC line must be switched
IGBTs cannot withstand high overloads
Fast enough (DC: no inductance XL to limit the current)
Only in case of DC fault and not during load change or AC fault

Consequences
Fault location (branch) detection within a few milliseconds
Too fast for communication between measurement devices
Independent detection systems
Opening at both sides of the faulted line
No opening of other branches
Backup in case this fails
New superfast DC breakers must be developed
Waiting longer results in more difﬁcult switching and is lethal for the IGBTs


Protection

Example: 4 terminal MT HVDC system



Protection

Fault occurs in the DC circuit (t = 0)



Protection

Rapidly changing currents throughout the system

di
VDC = L · +R ·i
dt
VDC VDC R
i (t ) = + I0 − · e− L · t
R R



Protection

Protection system must indicate the faulted line

PS



Protection

Opening of the faulted line (t < 5ms)


Supergrids Controlling the supergrid

Power balance and flows

At any time, the power balance must be zero: ( i PAC →DC ) − Ploss = 0
Injections can be fully controlled (DC) but compensation for losses is
needed
Slack bus or distributed slack bus
Power flows are according to the laws of Kirchhoff
Redispatching of DC injections might be needed to change DC flows
and avoid congestion
The DC system flows are determined by the DC voltages at the
converter side



Interaction between AC and DC system

DC system will have a profound inﬂuence on AC system ﬂows
Changing the power injections between nodes can have important
consequences
How the interaction will/should be is not trivial, especially with multiple
zones and multiple synchronous zones
A VSC HVDC terminal is highly dynamic
Operation may not jeopardize AC system security (interactions between
AC and DC controls)
Operation of electrically close terminals may interfere
Potential to increase stability and damping in the system



Segmenting the AC system?
In synchronous AC systems, events propagate throughout the system
By subdividing current synchronous zones in different smaller zones,
this can be limited
Part of the synchronizing power would be lost as well
Might be an option for currently loosely or non-synchronized systems
(USA?)

DC Grid

AC Grid


Supergrids Techno-Economic approach to a supergrid

Potential benefits of a supergrid

Income: 4 clear economic benefits
1 Access to remote energy sources
2 Higher penetration of renewable energy sources by improved balancing
3 Improved grid security
4 Reduced congestion in the system

Costs: expensive installation
HVDC terminals and cables are expensive
There are other resources besides renewables (generation mix)
Radial HVDC links to shore are possible as well
AC system upgrades might be sufficient for many years

Pay-back time
Is it interesting from an economic point of view to install a supergrid?


Supergrids Techno-Economic approach to a supergrid

Regulations and ownership
Many operational questions remain
Who will own/invest in the supergrid?
TSOs (ENTSO-E?)
Governments/EU
Generator companies
Private investors
The investor wants a return on investment!
The owner determines how the grid will look like
How many connections
Which connection points
How is the combined AC and DC power system operated?
How will money be earned?
Regulated market
Merchant grid
Connection charges for offshore generators
Who will be the regulating authority?
Multi-zonal regulations?

Conclusions

1 Introduction
Course overview
Situation sketch
Introduction
How to coordinate?
4 Supergrids
A supergrid?
5 Conclusions


Conclusions

Conclusions 1: coordination

In the multi-zonal transmission system, coordination is not trivial
Cooperation exists, but can be better
Coreso is a new and promising initiative
Power flow controlling devices are increasingly present in the grid
PFCs influence losses, transmission capacity, security,. . .
PFCs influence the operation of the local transmission system
. . . also that of neighbors
Make coordination even more important
Different manners of coordination are possible
Until now, no true coordination exists
First step: communicate
Second step: implemented in the regional initiatives framework/coreso
Optimum would be full coordination, with a single European TSO?
The current situation is not ideal nor a full implementation of the IEM


Mini-Course on Future Electric Grids Part 2

Mini-Course on Future Electric Grids Part 2

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