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Role of Multi-infeed VSC-HVDC on Dynamic Behaviour of
Future North Scotland Transmission System
Rakibuzzaman Shah, Robin Preece and Mike Barnes
School of Electrical and Electronic Engineering, The University of Manchester, M13 9PL, United Kingdom
E-mail: [email protected]; [email protected]; [email protected]
Keywords: Dynamic interaction, multi-infeed HVDC, North
Scotland system, outer controller.
called multi-infeed (MI)-HVDC system, especially in the
North of Scotland as reported in [3].
The MI-HVDC has more flexibility and transmission
capacity, which can improve the controllability and reliability
of the whole AC system. However, as reported in [4-7], the
mutual interaction between HVDC links within MI-HVDC
can bring a number of operational challenges in power
systems. Since most of the globally installed HVDC links are
based on the line-commutated converter (LCC), voltage
stability has been identified as the key concern in such a
mixed AC-DC system [4-6]. The developments in VSC
technology and controls are making VSC-HVDC a strong
option for HVDC connections. However, to date, limited
research has focussed on the operational challenges
associated with a mixed AC-DC system with multi-infeed
VSC-HVDCs except [7], where an outer controller selection
of multi-infeed VSC-HVDC considering the stability aspects
of the AC-DC system is addressed. However, it articulates
quite generic and far-reaching conclusions based on a limited
number of operating conditions in a naïve test system.
Due to the expected proliferation of HVDC systems up to and
beyond 2020 into the Great British transmission network, it is
anticipated that in some locations two or more HVDC
converter stations will be installed with only a short electrical
distance between them and will form a multi-infeed (MI)HVDC system. This is a particular concern in the North of
Scotland. This paper investigates the impact of MI-HVDC
links on the North Scotland system for two different system
generation mixes. A list of control schemes has been
formulated to assess the dynamic performance of the
developed realistic system under typical loading scenarios.
The work has been conducted in a DIgSILENT Power
Factory using case study simulations of the integrated North
Scotland system model. From the set of case studies, it has
been found that the AC voltage control allocation within the
HVDC links has a significant influence on the smalldisturbance angle and transient voltage stability of the system.
It is anticipated that two or more HVDC links will be
installed with only a short electrical distance in the North
Scotland system. Therefore, it is important for the GB
transmission system operator to have a greater clarity of the
dynamic behaviour of the North Scotland system with MIHVDC. This study, therefore, has analysed the impact of
VSC-based MI-HVDC links on the dynamics of the North
Scotland system under electromechanical transient timeframe. A variety of test case studies including varied
operating conditions and control configurations have been
conducted and reported in this paper.
1 Introduction
High voltage DC (HVDC) transmission systems are
recognized around the world as the prospective technology to
integrate the large far-from-shore wind power plants (WPPs)
and asynchronous AC grids [1]. It is also a leading candidate
for AC grid reinforcement. Since most of the UK’s suitable
offshore sites for wind power are located a significant
distance from shore (i.e. more than 100 km), a large portion
of these new WPPs in the UK will be connected through
HVDC links. Moreover, the growing desire to interconnect
with the asynchronous grids in North Sea region will increase
the use of HVDC links, especially VSC-HVDC in the Northeast of UK [2, 3].
2 System Modelling
The test system illustrated in Fig. 1 has been designed as a
reduced dynamic equivalent of the North Scotland power
system, henceforth referred as reduced North Scotland (RNS)
system in this paper. The basis for this model is obtained from
the GB network and published previously in [8, 9]. To
represent the RNS system, the network elements beyond the
node 4 of the original GB system have not been considered
for this reduced test system. Therefore, the network elements
beyond node 4 are represented as an external grid behind a
high voltage transformer.
Currently, there are four HVDC links connecting the Great
Britain (GB) transmission system to other asynchronous
grids: IFA to France, Moyle to Northern Ireland, BritNed to
Netherlands, and EWIC to Ireland. It is expected that this type
of interconnection will increase in the future, and five more
HVDC links to interconnect GB transmission system to other
asynchronous grids are due to be commissioned by 2020. Due
to the incremental use of HVDC systems, it is expected that
two or more HVDC links will feed into the UK’s transmission
network within a short electrical distance and will form a so-
The RNS model consists of four nodes interconnected
through transmission lines. In addition to the original nodes 1
to 4 from the initial GB model, a further node (node 5), is
added to the test system to facilitate the integration of the
HVDC infeed to represent the Caithness-Moray link (see Fig.
2). All AC transmission lines consist of a double circuit,
except for line 2‒3 which is a single circuit only. These
transmission lines represent the main power flow across
North Scotland. All the transmission lines have a nominal
voltage of 275 kV. HVDC infeeds representative of the
Western Isles and the Northconnect will be integrated with
the AC system model at node 1 and 2, shown in Fig. 2.
The modelling of generator controllers is essential to ensure
the realistic dynamic performance of the AC system.
Depending on the focus of the study this can include exciters,
power system stabilizers (PSSs), and governors. For this
study, governor models are not important since the focus of
the simulations is in the electromechanical transient timeframe which is faster than the action of the governors. For the
test system, the DC1A excitation system is used in all the
generation types since this has widely been implemented by
industry for coal, gas, and hydro plants. PSSs have been
added to the system and have been designed based on the
single machine infinite bus (SMIB) model of every generator
in the system.
System demand is modelled at the high voltage buses as a
static load as given in [9]. Since the detailed information of
load compositions is not available, the dynamic simulations
will be conducted using a polynomial load model, i.e. a
combination of constant impedance, constant current, and
constant power, (ZIP) load model. This model has been
widely used by utilities [10].
The resulting “RNS model” has a total installed generation
capacity of approximately 6.98 GW, with a demand (at nodes
1-5) of 2.95 GW. A further 2.24 GW flows from the RNS
system to the external grid (i.e. to Southern Scotland, England
and Wales).
3 Generic VSC-HVDC Control
Fig. 1: Single-line diagram of RNS network.
This section presents a generic primary control structure for
VSC-HVDC converters suitable for studies on an
electromechanical dynamic time-frame. The average value
model (AVM) of VSC-HVDC system presented in [11] has
been used throughout this study. A positive sequence phasor
representation is used for the AC system when performing
dynamic studies in an electromechanical time-frame, which is
compatible with balanced AC system studies. Hence, a
negative sequence current control is neglected [11]. The
control system analysis is based on the per unit representation
of the controller transfer function to avoid the complications
associated with different ratings and units [11]. An internal
model control (IMC) tuning method given as in (1) has been
used to obtain robust current loop controller settings [11]. All
VSC-HVDC infeeds model are standardized at 1000 MW.
Fig. 2: Representative RNS network with proposed HVDC
Dynamic data is required for the developed RNS system to
perform dynamic analysis with MI-HVDC links. This
includes the detailed modelling of the generators, excitation
systems, and power system stabilizers (PSSs). The type of
generator in each node is selected based on their
corresponding contribution on that node. The resulting
dominant generator types in the RNS network model are
summarized in Table 1. A Sixth order synchronous generator
model has been used for all units. The selected generation
types are parameterized with corresponding data as
recommended in [9].
Generator type
Hydro unit
CCGT unit
Fossil fuel unit (coal)
G( s ) 
 1 
 Ls  R 
1 
 des  1 
 kp 
 des
,ki 
 des
In (1), L is the inductance of the reactor, R is the resistance
of the reactor, and  des is the desired time constant of the
closed-loop step response.
The generic model of the DC voltage (VDC)/active power (P),
and AC voltage (VAC)/reactive power (Q) controllers as
shown in Fig. 3 are implemented in VSC-HVDC links for
Table 1: Generator types.
dynamic simulations. The detail of these controllers can be
found in [12] and the references therein. Moreover, the
feedforward reactive power controller in [10] is amended by
Ptanϴ to articulate the power factor (pf) control. For this
study, a point-to-point HVDC link with detailed models of
grid-side and remote converters and controls has been
employed. A voltage source has been used to represent the
distant power system at the remote end of the converter. A
detailed DC cable model (i.e. distributed features of DC
cables and frequency dependent models) gives more accurate
results whereas the nominal pi model of a DC cable might be
more numerically stable in simulations than the distributed
model. The distributed features of DC cable modelling or
frequency dependent DC cable model cannot be utilized in
DIgSILENT Power Factory [13]. Therefore, a cascaded PI
model has been employed to represent the DC cables for the
proposed studies to achieve the higher model fidelity on the
analysis time-frame of interest.
In (2), N is the total number of buses in the system, T is the
time-frame considered for evaluating TVSI, Tc is the fault
clearing time, and TVDI i ,t is the transient voltage deviation
Fig. 3: VSC-HVDC primary control system.
Two cases have been used: (1) with a current generation mix
as defined for 2013; and (2) with an anticipated generation
mix representative of 2023. Conventional generator models
are used to form the dynamic model of the 2013 case,
whereas, for the 2023 generation scenario, the conventional
generator (Hydro) at GT-3 (see Fig. 1) is replaced by a large
wind generator [8]. A priority based current control limit has
been used for all control schemes listed in Table 2. To
facilitate the HVDC infeeds into the system, the loads at
nodes 1 and 2 are increased by 40%, from the summer peak
scenario as given in [10], referred as summer peak loading
condition in this paper. The winter peak loading
(approximately 150 % of the summer peak [10]) has also been
used to analyse the impacts of the MI-HVDC system in the
RNS network. It should be noted that identical summer and
winter peak loading conditions are used for both the
generation scenarios since it is reported that the load growth
will be minimum over the next seven to ten years’ time [15].
index of bus i at time t. The TVDI i ,t can be evaluated as (3):
TVDI i ,t 
4.2 Control schemes and test cases
A number of different hierarchical control schemes can be
implemented in a VSC-HVDC system. In a MI-HVDC
scheme, the control method might be dictated by the
application. It is, therefore, possible that the MI-HVDC
system will be operated with different mode of operations. It
has previously been reported that the VSC-HVDC outer
controllers have significant impacts in the AC-DC dynamics
of the system [10]. Hence, in this study, different
combinations of outer control schemes, listed in Table 2, are
used to analyse the effects of MI-HVDC control
characteristics on the dynamics of the host AC system. It is
acknowledged that control combinations other than these can
be encountered in real systems. However, the idea behind the
selection of these control combinations is to illustrate the
effects of divergent control characteristics at different VSCHVDC terminal in the MI-HVDC scheme and identify
scenarios for further detailed study and analysis.
From the perspective of AC-side small-disturbance rotor angle
stability, the investigation focuses on the impact of the MIHVDC control allocation on the damping of various
electromechanical (EM) modes of the system. The QR
analysis method has been used to evaluate the eigenvalues to
the frequency of interest (0.2‒3.0 Hz) and the corresponding
damping ratios are calculated.
Short-term voltage stability (transient voltage stability) mainly
focuses on the transient voltage limit violation, delayed
voltage recovery or fast voltage collapse following a largedisturbance to the system. To measure the transient voltage
stability of the system, a transient voltage severity index
(TVSI) proposed in [14] has been used in this paper. Transient
voltage performance of the system buses following the
clearance of the fault can be evaluated as (2):
4.3 Small-disturbance angle stability analysis
The aim is to investigate the host AC system EM modes
under the effect of various control combinations (see Table 2)
within a MI-HVDC system and the given operating points of
the AC system. The damping ratios of the EM modes without
the proposed HVDC links to the RNS system (referred as the
  TVDI i ,t
i 1 t Tc
N  T  Tc 
and Vi ,0 is the nominal voltage of bus i. From (2), it is evident
that the smaller TVSI value means the better transient voltage
performance of the system.
4.1 Stability Indices
Vi ,0
In (3), Vi ,t refers to the voltage magnitude of bus i at time t,
4 Numerical Analysis
Vi ,t  Vi ,0
base case) are given in Table 3 for a clear comparison. The
damping ratios of the EM modes for 2013 and 2023
generation scenarios are demonstrated in Fig. 4 and 5 under
summer and winter peak loading conditions.
Grid-side converter
Vdc-Q (all)
Vdc-Q (W), Vdc- Vac (CM);
Vdc-pf (N)
Vdc-Q (N), Vdc- Vac (W);
Vdc-pf (CM)
Vdc-Q (CM), Vdc- Vac (N);
Vdc-pf (W)
Vdc-Q (W,CM), PQ (N)
Vdc- Vac (W,CM), PQ (N)
three-phase fault clearance can be seen, which is in agreement
with the results given in Fig. 4 and 5.
Remote converter
PQ (all)
PQ (all)
PQ (W,CM), VdcQ (N)
PQ (W,CM), VdcQ (N)
W = Western Isles; CM = Caithness-Moray; N = Northconnect
Table 2: Control schemes for converter stations.
EM mode ID
Damping ratio
Frequency (Hz)
Table 3: EM modes of the RNS system without HVDC links.
Fig. 4: Damping of EM modes for 2013 generation scenario
(a) summer peak
(b) winter peak
Examining the results in Fig. 4, it is seen that the damping of
the mode 4 (inter-area mode) is reduced for all control
combinations (the only exception is CI-3 under summer peak)
within MI-HVDC system, and the system experienced the
lowest inter-area mode damping under CI-4. From the results
in the figure, it can be seen that the damping of mode 1 is
almost kept constant at the base case value for CI-1 and CI-2,
and is reduced from the base case for other control
combinations. Furthermore, with the integration of the
proposed HVDC links, the damping of mode 2 is reduced
from the base case, however, it is not significantly affected by
the control allocation within the MI-HVDC. On the contrary,
the damping of mode 3 is increased from the base case for CI1 and CI-2, however, is reduced for other control
combinations. Looking at the results presented in Fig. 5, it
can be seen that the damping of the inter-area mode is
reduced from the base case for the 2023 generation scenario.
Mode 1 of the system is eliminated for this scenario due to the
replacement of the synchronous generator with a full
converter WPP at GT-3. The damping of mode 2 is reduced
from the base case, however, is not significantly affected by
the control allocation within the MI-HVDC. Similar to the
previous study, the damping of mode 3 shows an increasing
trend for CI-1 and 2, and a decreasing trend for other control
It is identified that the CI-4 in MI-HVDC has the most
adverse effect on the inter-area mode of the system.
Therefore, the effect of CI-4 at MI-HVDC system is validated
by time domain simulations presented in Fig. 6. The active
power responses of a single line between node 2 and 4
following a three-phase fault at node 3 for 80 ms are given in
Fig. 6. Sustained oscillations of line active power following a
Fig. 5: Damping of EM modes for 2023 generation scenario
(a) summer peak
(b) winter peak
voltage control of the system. The dynamic responses of the
DC-link voltages following a disturbance to the AC system
are presented in Fig. 8. Analysis has been conducted for
various operation scenarios. Since the DC voltage responses
of different operating conditions display very similar dynamic
behaviour, the DC voltage response results for 2013
generation scenario at summer peak are presented here for
brevity. From the figure, it can be seen that DC link voltages
are effectively maintained within acceptable limits by the
designed DC voltage controllers. From the results in Fig. 8, it
can be seen that the DC voltage excursion following the fault
clearance is affected by the MI-HVDC control combinations.
Moreover, it should be noted that following the fault in node
3 at 12.5 s, the DC link voltage of the grid-side converter at
Northconnect is reduced for CI-5 and CI-6 control
combination since the grid-side converter at Northconnect is
operating in rectifier mode under those control combinations.
Fig. 6: Line 2-4 power responses for CI-4 at different
generation scenarios.
4.4 Transient voltage stability analysis
In a converter dominated power system, transient voltage
stability is becoming important due to the voltage or reactive
power management issues associated with converters and
synchronous generators in the system. The effect of MIHVDC control combinations on the transient voltage stability
is presented in this section by considering the transient
voltage severity index illustrated in Section 4.1. The TVSIs
are assessed for 2013 and 2023 generation mixes under
summer and winter peak loading for a three-phase fault at
node 3 and 5 of the RNS system.
The TVSI of the system for 2013 generation scenario is given
in Fig. 7 (a). Examining the upper and lower ranges of TVSI
across all control combinations, it can be obtained that the CI1 has the most adverse effect on the transient voltage stability
of the system (a larger TVSI value corresponds to the lower
transient voltage stability level). From the figure, it can also
be seen that the CI-6 could claim to outperform the other
control combinations given in Table 2. Voltage control is
applied to the grid-side converters of the proposed Western
Isles and Caithness-Moray HVDC link under CI-6. This
enables fast dynamic reactive power management to the
system nodes after the fault clearance, resulting in a better
transient voltage stability level for the system.
The TVSI of the system for 2023 generation scenario is given
in Fig. 7 (b). For 2023 generation scenario, it is assumed that
the WPP at GT-3 (see Fig. 1) is operating at constant power
factor mode. Comparing the upper and lower ranges of all
TVSIs for the given control combinations, it is evident that
CI-1 is adversely affecting the transient voltage stability of
the system. Comparably, CI-6 provides the enhanced transient
voltage stability level among all control combinations
considered in this study. It should be noted that the interaction
among VSC-HVDC reactive power and generator excitation
controls causes the higher transient overvoltage following the
fault clearance under 2013 generation scenario, thereby,
having the higher value of TVSIs for all control combinations
as compared to the 2023 generation scenario.
Fig. 7: Transient voltage severity index
(a) 2013 generation scenario
(b) 2023 generation scenario
5 Conclusions
This study has investigated the impacts of the planned MIHVDC system on the dynamic behaviour of the representative
North Scotland power transmission system. The study has
been conducted by investigating the influence of various
control combinations of the proposed HVDC links on the host
AC system small-disturbance angle and transient voltage
stability. From the results given in this paper, it can be seen
that the outer controller allocation within the MI-HVDC
system has a significant influence on the small-disturbance
angle and transient voltage stability of the system. Based on
the set of simulation results it can be concluded that the
4.5 DC system effect
The dynamic response of the DC-side is much faster than the
AC-side of the system, thereby, are shown by the DC-side
transient responses. It has been reported that the VSC-HVDC
operating points and grid strength may affect the DC-link
transient voltage stability performance of the system is
improved when AC voltage control is applied to the Western
Isles and Caithness-Moray HVDC link. However, it has
demonstrated an aggravated impact on the small-disturbance
angle stability of the RNS system.
Fig. 8: DC voltage responses of grid-side converter
(a) Western Isles
(b) Caithness-Moray
(c) Northconnect
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