Power System Security in a Meshed North Sea HVDC Grid

INV ITEDP A P E R

Power System Security in aMeshed North Sea HVDC GridThe impact of wind power variation on ac grids is presented where the

challenges can be properly managed by the use of meshed high-voltage

dc (HVDC) grids.

By Temesgen M. Haileselassie and Kjetil Uhlen, Member IEEE

ABSTRACT | There are very ambitious plans in Europe for

changing the energy infrastructure in order to reduce green-

house gas emissions. This involves scenarios where renewable

energy sources by 2050 will meet almost 100% of the electric

power demand. This has spurred offshore wind farm develop-

ment activities in the North Sea due to the vast wind energy

potential in this region and the potential lack of suitable on-

shore sites in the future. Large-scale wind farms in the North

Sea pose grid integration challenges such as the need for long-

distance subsea power transmission and tackling the impact of

wind power variation on alternating current (ac) grids. These

challenges can be properly managed by the use of meshed

high-voltage direct current (HVDC) grids. Three of the regional

groups (RGs) in the European Network of Transmission System

Operators for Electricity (ENTSO-E), namely Regional Group

Great Britain (RG-GB), Regional Group Nordic (RG-N), and Re-

gional Group Continental Europe (RG-CE), surround the North

Sea area. A meshed North Sea HVDC interconnection between

offshore wind farms and these three asynchronous ac grids can

also enable market integration of the otherwise separate

regions. This, in turn, results in better utilization of generation

and transmission infrastructures, improved security of power

supply, and maximized utilization of renewable energy re-

sources. In this paper, a test scenario of a meshed North Sea

HVDC grid is studied to demonstrate the potential of such a

system for enhancing power supply security of the ac grids.

Simulation studies of the test case show that with proper con-

trol techniques, a meshed North Sea HVDC grid can mitigate the

effect of wind power variation by facilitating exchange of pri-

mary and secondary reserves between asynchronous ac grids.

KEYWORDS | Integration of offshore wind power; meshed high-

voltage direct current (HVDC) grid; power system security

I . INTRODUCTION

By adopting the Energy Roadmap 2050 [1], the European

Commission has committed to reducing the greenhouse gasemissions to 80%–95% below 1990 levels by 2050. The

share of renewable energy (RES) in this scenario will be

around 50% in gross final energy consumption. The share

of RES in electricity consumption could be as high as 97%

and wind power is expected to contribute approximately

50% of the renewable energy [2]. Given the limited size of

other available renewable energy sources, a lot of attention

has been given to development of wind farms in Europe.Due to the fact that most of the suitable sites for wind

power generation in continental Europe have already been

used up, more and more of the recent wind farms are being

located at offshore sites. The North Sea in particular is

endowed with vast amount of wind energy resources and,

hence, the most notable offshore wind farm developments

are concentrated in this region. Bard-1, Norfolk Bank, and

Dogger Bank wind farm projects could highlight some ofthe offshore wind farm development activities in this

region. By harnessing the vast potential of offshore wind

energy, the European Union can be able to significantly

reduce its energy dependency on imports from external

regions.

Despite the benefits of offshore wind farms, the varia-

bility of power production means that alternating current

(ac) grid systems must provide more balancing power. As aresult, the total cost of keeping reserves increases with

increasing wind power penetration. Integration of the

asynchronous ac grids in the North Sea region [i.e.,

Manuscript received September 13, 2011; revised May 20, 2012 and January 4, 2013;

accepted January 7, 2013. Date of publication February 22, 2013; date of current

version March 15, 2013.

The authors are with the Department of Electric Power Engineering,

Norwegian University of Science and Technology, Trondheim N-7491, Norway

(e-mail: [email protected]; [email protected]).

Digital Object Identifier: 10.1109/JPROC.2013.2241375

978 Proceedings of the IEEE | Vol. 101, No. 4, April 2013 0018-9219/$31.00 �2013 IEEE

Regional Group Great Britain (RG–GB), Regional GroupNordic (RG–N), and Regional Group Continental Europe

(RG–CE)] can help to alleviate this challenge in two

ways.

On the one hand, the total variation of wind power

production decreases with increasing geographical

distribution of wind farms (i.e., interconnection of widely

dispersed wind farms into a common power system pool).

The relative variations in total loads will also be smallerwith increasing power system size (and, hence, with in-

creasing interconnections). Hence, a stronger North Sea

interconnection can help to minimize the net demand of

balancing power created by higher penetration of wind

power.

Furthermore, the North Sea interconnections can ena-

ble exchange of primary and secondary reserves between

the three asynchronous ac grids and, as a result, enhancefrequency responses of the ac grids.

Recent developments of wind farms in remote loca-

tions, particularly in remote offshore sites, have steadily

increased the demand for more robust, efficient, and re-

liable grid integration solutions. In this respect, voltage

source converter (VSC)-based HVDC technology with

point-to-point connection is taking the lead in several new

offshore wind power projects due to its advantages for suchapplications. VSC-based HVDC offers long-distance bulk

power transmission capacity, enables interconnection of

asynchronous ac grids, and offers black start capability and

reactive power support [3]. In places where several HVDC

connections are located close to each other, an HVDC grid

(also called multiterminal HVDC) has the potential to in-

crease transmission capacity, system reliability, and elec-

tricity market opportunities.The objective of this paper is to demonstrate, with the

help of simulation results, the potential of a meshed

HVDC grid for power supply security and market integ-

ration in the North Sea region. The paper is outlined as

follows. Section II discusses power system security and

power flow control in traditional ac grids. Section III

deals with an overview of meshed HVDC grids and their

potential applications in the North Sea region. Control ofmeshed HVDC grids is discussed in Section IV. In

Section V, the performance of a meshed North Sea

HVDC grid is analyzed based on simulation results.

Market integration of ac grids with a meshed HVDC grid

is discussed in Section VI. This is followed by Section VII,

which discusses further challenges of developing a meshed

North Sea HVDC grid. Finally, conclusions are drawn

in Section VIII.

II . POWER SYSTEM SECURITY AND GRIDFREQUENCY CONTROL

Power interruption in the modern society is a very costly

phenomenon. Power system operators put utmost efforts

to ensure maximum security and reliability of power

supply thereby minimizing the probabilities of occurrencesof such conditions. Security of a power system refers to the

degree of risk in its ability to survive disturbances (con-

tingencies) without interruption of customer services [4],

[5]. The contingencies include outages such as sudden and

unscheduled loss of service of one or more of the main

power system components (generators, transformers,

transmission lines, converter stations, etc.), usually due

to a fault or system malfunction.The level of power system security is dependent upon

the actual operating condition, the type and probability of

outages, and the response to the outage conditions. Due to

the fast system response required to mitigate the effects of

outage conditions, power system security is an important

factor that must be taken into consideration both during

system planning as well as control design and implemen-

tation phases. Power systems are normally operated ac-cording to the deterministic ðN � 1Þ criterion or possibly

with some risk-based adaptations to this. In [6], some of

the most commonly used security evaluation indices are

discussed.

The N � 1 security criterion means that if the service of

one power system component is lost permanently, the re-

maining system must be capable of stable operation,

compensating for the lost service and supply all loadswithout exceeding operating limits.

Due to redundancy in meshed ac networks, it is possi-

ble to enforce N � 1 security for power transmission. With

outage of one line or transformer, power flow can be

maintained via the other transmission paths without ex-

ceeding the transmission capacity of any of the transmis-

sion lines.

N � 1 security criterion in the context of powergeneration can be obtained accordingly. In the event of

outage of one generation unit, the remaining units in the

ac grid must be able to compensate for the lost gener-

ation without any one of them exceeding its operating

limits.

Frequency droop control is the means by which N � 1

security can be achieved for power generation in an inter-

connected system. Since frequency droop control enablesa shared responsibility of power balancing among several

generation units, power production levels change

smoothly, thereby reducing the stress associated with

abrupt changes in generated power.

In Fig. 1, typical characteristic curves for generation

and load are shown. The slope of the generation line is a

measure of frequency droop constant of the aggregate

generation. Assuming negligible transmission losses, thesteady-state operating point is determined by the inter-

section of aggregate load line and aggregate generation line

in the frequency ðfÞ versus power ðPÞ plane.

The intersection of the generation line and the load

line gives the operating point of the ac system at steady-

state conditions. The slope of the generation line comes

from frequency droop control of generator units whereas

Haileselassie and Uhlen: Power System Security in a Meshed North Sea HVDC Grid

Vol. 101, No. 4, April 2013 | Proceedings of the IEEE 979

the load line usually shows a small degree of frequency

dependency.

Grid frequency control traditionally consists of three

different control actions with differing times of responses.

These are primary control, secondary control, and tertiary

control [7], [8]. Primary control refers to the response ofgeneration control to load changes (or outage of a gener-

ation unit). In a droop controlled ac system, change in load

results in steady-state frequency deviation (compared to

the original level). This is shown in Fig. 2, where PG0 and

PL0 refer to the initial generation line and load line of the

ac grid system.

In Fig. 2, point A refers to the initial steady-state ope-

rating point. When load power is increased, the load lineshifts to the right (i.e., from PL0 to PL1), and as a result, the

steady-state operating point also moves from point A to

point B. This transition corresponds to primary frequency

control. Since the primary control results in a steady-state

frequency deviation (frequency decrement/increment

resulting in load increment/decrement), secondary control

is needed to restore system frequency back to the initial

(desired) level. The effect of secondary control is theshifting of the generation characteristic line so that the

system frequency gets restored to the original level. In

the case of Fig. 2, this (i.e., the secondary control) corre-

sponds to the shifting of the generation line from PG0 to

PG1. As a result, the steady-state operating point changes

from point B to point C, implying restoration of frequency.

Loss of one of the many generation units also leads tosimilar control responses as shown in Fig. 3.

In the event of an outage of a generator unit in a

multimachine grid system, the generation characteristic

line shifts to the left (corresponding to the shift from PG0

to PG1 in Fig. 3). This results in a drop in grid frequency

and, to a smaller degree, a reduction in power consumed

by the load. To restore system frequency back to the

nominal value, the generation line has to shift upwards(i.e., from PG1 to PG2). Secondary control is achieved by

load-frequency control in the case of interconnected ac

systems.

Apart from primary and secondary controls, the tertiary

control is used to reschedule generation based upon the

latest available data about the power system after the oc-

currence of load change or a unit outage. The time response

of frequency and reserves activation are shown in Fig. 4.As shown in Fig. 4, after occurrence of large frequency

disturbance, the primary control is responsible for the

frequency response ðRÞ in the first minute. Frequency re-

sponse ðRÞ is defined as the amount of extra power gener-

ated for each unit decrement of grid frequency. The

secondary controller frees up some of the primary reserves

Fig. 2. Change in the load line and responses of primary and

secondary controls (see [8, p. 263]).

Fig. 3. Change in the generation line (due to loss of a generator unit)

and responses of primary and secondary controls.

Fig. 4. Activation of reserves and time response of grid frequency.

Fig. 1. Determination of steady-state operating point in ac grids.


980 Proceedings of the IEEE | Vol. 101, No. 4, April 2013

already in use. The response time could span around15 min after the occurrence of the load change (or

outage of the generation unit). Finally, the tertiary

controller frees up the secondary reserves in the next

40–60 min.

When renewable energy resources with variable power

production capacity are introduced into the ac grid, they

incur new challenges to the grid frequency control. These

challenges can be summarized as follows.1) Primary control: There will be less primary re-

serves if a new generation (such as a wind farm)

provides less/no frequency response, in which

case more spinning reserves will be required to

provide sufficient frequency response with the

new generation.

2) Secondary control: With further addition of a va-

riable generation such as wind farms into thepower system, there will be a need for more sec-

ondary reserves.

3) Tertiary control: Without new interconnections to

other areas (or ac grids), there will be limited

size of electricity market for the wind power in

times of an ample generation. New interconnec-

tions between ac grids, which otherwise are se-

parate from each other, will give access to largercontrol areas and, as a result, enable exchange of

reserves.

III . MESHED HVDC GRID ANDPOTENTIALS OF ITS APPLICATIONIN THE NORTH SEA REGION

A. Meshed HVDC GridCurrently, there are two types of HVDC transmission

technologies, namely: line commutated converter (LCC)-

based and VSC-based types. Both types of HVDC tech-

nologies have so far been limited to two-terminal (also

called point-to-point) power transmission. Early attempts

to use LCC–HVDC in multiterminal configuration have

given only limited results mainly due to the complexities ofthe controllers for such configuration and also due to the

need for fast communication between controllers of all

HVDC terminal stations.

Despite the many decades of experiences with

LCC–HVDC, the Sardinia–Corsica–Italy (SACOI) HVDC

transmission and the Quebec–New England HVDC

transmission have remained to be the only multipoint

LCC–HVDC transmissions currently in service. On theother hand, the arrival of VSC–HVDC technology a decade

ago has revived research and development activities in the

area of multiterminal HVDC operation. The main reasons

for this are flexibility and simple natures of the active

power controller, reactive power controller, and direct

current (dc) voltage controller used in VSC–HVDC,

which in turn enable autonomous control of individual

converters without involving fast communication be-

tween different terminals.

Hence, this paper focuses on the VSC-type HVDC for

the dc grid application. With this understanding, in the

rest of this paper, the terms HVDC grid and dc grid impli-

citly will refer to the VSC type of the HVDC grid.HVDC grids are formed by interconnecting the dc

busses of three or more converters to a common dc trans-

mission network, whereas the respective ac sides of the

converters may be connected either to the same (syn-

chronous) ac networks or different (asynchronous) ac

networks. HVDC grids can be roughly grouped into two

topologies, namely: radial and meshed. In the radial dc

grid topology, there is only one unique power transmis-sion route between any two terminals. Hence, if one of

the dc transmission lines that make up this route is dis-

connected, power flow between the two terminals will

be disrupted. An example of a radial topology is shown

in Fig. 5(a).

In the case of the meshed topology, there are two or

more alternative power transmission routes between two

specific terminals. An example of the meshed topology isshown in Fig. 5(b). Like in the case of the meshed ac

network, meshed dc grid can provide N � 1 security of

power transmission during outage of one of the dc trans-

mission lines.

In addition, the HVDC grid operation requires that at

least one of the converter stations be assigned as dc voltage

regulator. This implies that apart from enhancing security

of the dc transmission routes, it is necessary to ensureN � 1 security for operation of the VSC–HVDC stations.

Hence, N � 1 security in the context of the multiterminal

VSC–HVDC system must also fulfill the following

conditions.

1) The dc grid consists of two or more dc voltage

regulating HVDC stations.

2) In the event of the outage of one of the dc voltage

regulating converter stations, the remaining onesmust be able to manage dc voltage regulation

without any one of them exceeding its operating

limits.

N � 1 security in the dc grid operation can be achieved

by using dc voltage droop control for two or more of the

Fig. 5. HVDC grid topologies. (a) Radial topology. (b) Mesh topology.



VSC–HVDC terminals constituting the dc grid (in similarmanner as frequency droop control is used for synchro-

nous generators).

B. Potential Advantages of Using Meshed HVDC inthe North Sea Region

The North Sea region has unique features which make

meshed HVDC grid an attractive solution for the grid in-

tegration problem. Among these special features, the mostsalient ones are listed below.

1) The presence of three asynchronous ac grids,

namely: RG–N, RG–GB, and RG–CE grid systems.

Interconnecting asynchronous grids with the

HVDC transmission system enables fast and flexi-

ble power flow control in a wider region.

2) Large potential for developing offshore wind

farms in the North Sea. The variable generationfrom wind farms means that there must be more

primary and secondary reserves in the power sys-

tems to compensate for the power fluctuations.

This demand can be met by increasing intercon-

nection of the wind farms with ac grids with

power demands as well as increasing intercon-

nection with ac grids which have available balanc-

ing power. Interconnection between neighboringac grids will also enlarge the effective size of the

market, which is beneficial both for increased

competition and for integrations of large amounts

of variable wind power [9].

3) The large hydropower generation capacity of

Norway can be used for provision of the primary

and secondary reserves required for new large-

scale offshore wind farms in the North Sea.4) The offshore loads in the North Sea (i.e., oil and gas

platforms which mainly use gas fired turbines to

meet their power demand) can also benefit from

clean power supply from onshore grids and/or

from offshore wind farms via HVDC connections.

Moreover, the long offshore transmission distances

between the three mentioned ac grids mean that HVDC

technology will be an essential part of the grid integrationsolution.

The North Sea HVDC grid will not be developed as a

single large project, but in several steps of separate indi-

vidual projects. Offshore wind farm developments are

expected to continue based upon VSC–HVDC intercon-

nections with the three separate ac grids. Once there are a

substantial number of offshore wind farms in the North

Sea, the meshed VSC–HVDC grid can be formed on thebackbone of the already existing subsea power transmis-

sion infrastructure. Such scenario is shown in Fig. 6,

where the dark interconnection lines (encircled by solid

ellipses) show initial stage developments and the light

interconnection lines (encircled by dashed ellipse) show

the formation of the meshed North Sea HVDC grid

afterwards.

IV. CONTROL STRATEGY FOR MESHEDHVDC GRIDS

In the same manner as in the multimachine ac system, a

multiterminal HVDC system should have a mechanism for

instantaneous balancing of the power demand (outflow

from the dc grid via inverters) and power supply (inflow to

the dc grid via rectifiers). In the literature, two methods

are proposed, namely: master–slave control and dc voltage

droop control.In the master–slave control strategy, one converter

terminal (called master terminal) is dedicated for dc

voltage control, and hence for dc grid power balancing

[10], [11]. In the case of dc voltage droop control, two or

more terminals participate in dc voltage control [12]–[14].

The master–slave control strategy exposes the master

terminal to large stresses since this terminal will have to

handle all power fluctuations in the dc grid. In addition, ifthere is an outage of the master terminal, this will result in

an immediate outage of the entire HVDC grid.

In contrast, due to the distributed nature of dc voltage

regulation, dc voltage droop control enables the provision

of N � 1 security (in this case, an outage of an HVDC

terminal which could possibly be one of the terminals with

the droop control mode). In addition, since all dc grid

power fluctuations are distributed among several HVDCterminals, in the droop control mode, none of the

terminals will be exposed to excessive stress due to large

power flow fluctuations.

A VSC–HVDC link can be connected either to an active

ac grid or to a passive ac grid. In the active ac grid

connection, the grid will already have ac voltage prior to

the connection of the converter station. The converter

Fig. 6. Meshed North Sea HVDC grid scenario: blue lines show early

state developments and red lines show later stage development).



controller then synchronizes the ac voltage output of the

VSC–HVDC terminal according to the external ac voltage.

A VSC–HVDC with the active ac grid can actively control

its current flow, which in turn enables us to adopt any one

of the following control mode options:

1) constant power control mode;

2) constant dc voltage control (integral dc voltagecontrol) mode;

3) dc voltage droop control mode.

Block diagrams of the three types of VSC–HVDC

control modes are found in the Appendix. Further details

of the controllers and VSC–HVDC models can be referred

to [21]. DC voltage versus power flow characteristics of the

three types of control modes are shown in Fig. 7.

In the constant power control mode, the power flow viathe converter station is independent of the dc voltage. The

power flow may be controlled actively by the VSC–HVDC

controller (in the case of active ac grid connection) or by

the ac grid power demand (in the case of passive grid

connection).

In the case of passive grid connected VSC–HVDC, the

converter becomes the main (or possibly the only) source

of ac voltage, while power flow via the converter is deter-mined by the loads connected in the ac grid. As a result, a

passive grid connected VSC–HVDC appears as the con-

stant power controlled terminal [Fig. 7(a)] when observed

from the dc bus (i.e., power flow is independent of dc bus

voltage). HVDC link supplying power to an oil/gas plat-

form or to an island can be a typical example for passive

ac grid connection.

Constant dc voltage control refers to the integral con-trol of dc bus voltage and by doing so this particular ter-

minal provides all demand of instantaneous balancing

power. Neglecting the dc line losses, dc grid power ba-

lancing can be defined as elimination of any nonzero net

power flow into or out of the dc grid.

DC voltage droop control is characterized by linear

interdependency of dc bus voltage and the power flow via

the HVDC terminal. DC voltage versus power character-istic curve of the VSC–HVDC terminal with the three dif-

ferent control modes is shown in Fig. 7(c). The sign

convention in Fig. 7 is such that positive power implies the

rectifier mode of operation and negative power implies the

inverter mode of operation.

The performance of the three modes of HVDC control

can be analyzed with the help of the two-terminal HVDC

link model shown in Fig. 8.

In Fig. 8, the two HVDC terminals can represent the

aggregates of rectifiers and the aggregates of inverters.Hence, ignoring the dc line losses, the intersection of the

source power ðPSÞ and the load power ðPLÞ characteristic

lines in Fig. 9 gives the steady-state operating point.

As the load line in Fig. 9(a) changes (from PL0 to PL1),

the dc bus voltage remains unchanged. When droop con-

trol is used for the source HVDC terminal and fixed con-

trol for the load HVDC terminal, a change in the load line

is followed by a change in the dc voltage; i.e., transitionfrom an initial operating point A to a new operating point B,

as shown in Fig. 9(b).

In the case of droop control applied to both sides, the

shifting of either the source line or the load line affects the

steady-state power flow and the dc voltage as well, as

shown in Fig. 9(c).

DC grid response to a sudden change in the power flow

(i.e., transition from A to B) is referred here as primary dcvoltage response (analogous to primary frequency response

of ac grids). Since primary dc voltage response of droop

controlled multiterminal VSC–HVDC involves a steady-

state change in operating dc voltage, secondary control is

required to restore the dc voltage back to the desired level

if needed. The secondary controller can be activated

sometime after a steady-state dc voltage drop is observed,

and it acts more slowly compared to the primary controlaction. In Fig. 9(b) and (c), for example, the secondary

controller is activated half a minute after the drop in dc

voltage is observed, and it takes about 20 s to restore the

dc voltage to the original level. In Fig. 9(c), we can see

that the dc voltage drop is lower (between t ¼ 20 s and

t ¼ 50 s) due to the contribution of the inverter to dc

voltage droop control. But this advantage comes at the cost

of the lower power flow (�925 MW) compared to thedesired level (1000 MW). The desired power flow level is

achieved after the action of secondary control, as shown in

the time plot of Fig. 9(c) (after t ¼ 50 s).

In addition to transferring power based on the predefined

time schedule, HVDC interconnection can also be used to

Fig. 7. DC voltage versus power characteristic of VSC–HVDC terminals

with: (a) constant power control; (b) constant dc bus voltage control;

and (c) dc voltage droop control.

Fig. 8. Two-terminal (point-to-point) HVDC connection.



enhance frequency response of ac grids. Currently, HVDC

links are utilized for exchange of balancing reserves

(secondary and tertiary control) across ac interconnections.

This is commonly used, for example, on Skagerrak HVDC

link between Norway and Western Denmark. Likewise,

HVDC control can be extended to include the primary

frequency support (i.e., for frequency response enhance-ment) of ac grids. This can easily be achieved by adding

frequency droop loop in the HVDC converter power con-

troller [15]. Block diagrams of frequency droop control im-

plementation for VSC–HVDC are included in the Appendix.

V. MESHED NORTH SEA HVDCSCENARIO: SIMULATION STUDIES

Different interconnection scenarios have been proposed

in the literature for the meshed North Sea HVDC inter-

connection (sometimes referred to as the North Sea

supergrid). Fig. 10 shows different meshed North Sea

HVDC grid scenarios envisioned by Airtricity [16], Sintef

[17], Statnett [18], and the European Wind Energy

Association [19].

In this paper, a rather simplified scenario of the North

Sea supergrid has been considered for demonstrating its

potentials with the help of simulation studies.As shown in Fig. 11, the test scenario includes two

interconnections to RG–GB, one interconnection to the

Nordic grid, one interconnection to the RG–CE grid,

one interconnection to an offshore wind farm, and one

interconnection to an offshore load (oil and gas

platform).

Converter power and voltage ratings are chosen for

demonstration purpose only and do not represent anyspecific future plan for the North Sea supergrid. The elec-

tromagnetic transient simulation tool EMTDC/PSCAD was

used for modeling the test scenario.

Fig. 9. Steady-state operating points and corresponding time-domain responses: (a) constant dc voltage control on the rectifier side and

constant power control on the inverter side; (b) dc voltage droop control on the rectifier side and fixed power control on the inverter side;

and (c) dc voltage droop control on both sides.



A. Mitigation of Wind Power Fluctuation by PrimaryPower Balancing of HVDC Grid

In the test scenario, the offshore wind farm injects

variable wind power into the HVDC grid, and, as a result,

the dc bus voltages also show similar variations. The

HVDC terminals with dc voltage droop control (i.e., 1, 2,

and 4) respond by varying their power flow accordingly. In

contrast, the HVDC terminals with constant power control

(i.e., 3 and 5) remain unaffected by the dc bus voltage

variations.From the plots in Fig. 12 it is evident that the large

power flow variation from the offshore wind farm has

effectively been distributed to terminals 1, 2, and 4 (i.e.,

the HVDC terminals in the droop control mode), hence

demonstrating the capability of the meshed North Sea

HVDC grid for mitigating the impact of wind power

variation on the ac grid.

By varying the sizes of the dc voltage droop in thesethree HVDC terminals, it is possible to change the shares

of the dc grid balancing power coming from each converter

station. This is ultimately dependent upon the availability

of primary balancing power in the ac grids connected to

the meshed HVDC grids.

B. Coping With Loss of DC Line in the MeshedHVDC Grid

To show the supply security capability of a meshed

HVDC grid in the North Sea, outage of a dc line was

studied with the simulation model. DC line 1–2 is dis-

connected abruptly at t ¼ 90 s. This results in increased

power flow in some of the dc lines (line 1–3, line 1–4, and

line 3–4) such that the power injection at each of the

HVDC station remains nearly unaffected. A closer look at

Fig. 10. North Sea supergrid proposal by Airtricity (top left),

Sintef (top right), Statnett (bottom left), and the European Wind

Energy Association (bottom right).

Fig. 11. Test scenario of the meshed North Sea HVDC grid.

Fig. 12. Wind power variation and primary balancing by HVDC

terminals in the dc voltage droop mode.



the time plots in Fig. 13 shows that the terminals with dc

voltage droop control exhibit small amounts of power flow

deviations after outage of line 1–2. This is due to the dc

line resistances which result in unequal variations of the dc

bus voltages, which in turn affect the droop controllers.

Nonetheless, the simulation results show that the meshedHVDC grid with dc voltage droop control can ensure sup-

ply security even after loss of one of the dc lines consti-

tuting the meshed topology.

The dc line resistances dictate how much power each

dc line will transfer after the loss of line 1–2 (i.e., based on

Ohm’s law applied to the new dc grid topology as the

current injections at all nodes remain nearly the same as

prior to disconnection of line 1–2). Therefore, it is neces-sary that all the dc transmission lines with increased power

flow (i.e., line 1–3, line 1–4, and line 3–4) are dimen-

sioned to accommodate their respective power flows ob-

served after the line outage (i.e., after t ¼ 90 s in Fig. 13).

It is foreseen that power and energy is dispatched in

the dc grid by some market arrangement (as in ac grids),

by, for example, flow-based market coupling. Note, how-

ever, that the power flow in the individual lines can only befully controlled if the number of branches is smaller than

the number of converters (since Ohm’s law applies here as

well). Therefore, it is necessary that N � 1 security for dc

transmissions take the power transfer capacity limits of the

transmission lines as well as that power ratings of HVDC

terminals into account.

C. Response to Loss of Connection to OffshoreWind Farm

In Section III, it was argued that dc voltage droop

control enables the provision of N � 1 security in a meshed

HVDC grid. This feature becomes useful during loss of

connection to offshore wind farm (or loss of power gener-

ation from offshore wind farm). This can be seen from the

simulation results in Fig. 14, which shows that the con-

nection loss of the wind farm at t ¼ 85 s was compensatedby the droop controlled terminals (1, 2, and 4).

In this particular case, converters 1 and 4 (i.e., HVDC

connections to Scotland and RG–N) responded by in-

creasing the power injection into the dc grid while con-

verter 2 (i.e., HVDC connection to England) responded by

reducing the power it takes away from the dc grid. HVDC

terminal connected to RG–CE (i.e., terminal 3) was as-

signed to constant power mode and hence remained unaf-fected by the loss of wind power supply into the meshed

HVDC grid. Similarly, the power supply to the offshore oil/

gas platform remained uninterrupted despite the loss of

wind power injection. Here too it is necessary that con-

verters 1 and 4 have the capacity to accommodate for the

increased power flow observed after t ¼ 85 s in Fig. 14.

D. Primary Reserves Exchange via HVDC GridExchange of primary and secondary reserves between

the three ac grids (RG–N, RG–GB, and RG–CE) is possible

by means of meshed North Sea HVDC grid. This requires

the use of frequency droop control on the HVDC terminalpower flow controller, in addition to the dc voltage droop

described previously. Block diagrams of frequency droop

control for use with constant power control mode and dc

voltage control mode are shown in Fig. 20.

To demonstrate primary reserves exchange via HVDC

with the help of simulation study, a frequency droop

element was added to the HVDC terminal connected to the

Fig. 13. Response of meshed HVDC for an outage of the dc line.

Fig. 14. Response of the dc grid to loss of connection to offshore wind

farm. (Positive power implies inverter mode and negative power

implies rectifier mode of operation.)



RG–CE grid. Since this terminal was in constant power

control mode in previous cases, the new control structure

with the frequency droop control looks like Fig. 20(a) inthe Appendix.

A sudden loss of power generation unit of 1.2-GW

power rating inside the RG–CE was simulated and the

resulting responses are shown in Fig. 15. The RG–CE grid

is modeled with a frequency response of 10 GW/Hz.

The loss of power generation is followed by frequency

dipping in RG–CE, which in turn resulted in increased

power generation from synchronous generators in the gridsystem. Similarly, due to the frequency droop control,

converter 3 responds by injecting additional power into the

RG–CE grid after sensing the drop in frequency. Since the

additional power eventually comes from other ac grids (in

this case, from RG–N and RG–GB grid systems) frequency

oscillations will be observed in other ac grids as well (see

the frequency plots in Fig. 15).

Comparison of the frequency responses of the RG–CEgrid in the presence and absence of frequency support by

the North Sea HVDC grid is shown in Fig. 16. The ob-

served dipping in frequency of the RG–CE grid after loss of

generation unit is larger in the absence of frequency sup-

port from the meshed HVDC grid (compared to the case

where frequency support from the dc grid is available).

This demonstrates that a North Sea HVDC grid has the

potential for enhancing the frequency responses of theinterconnected ac grids.

VI. HIERARCHICAL MARKET-ORIENTEDPOWER FLOW CONTROL IN A POWERSYSTEM CONSISTING OF HVDC GRIDS

At the highest level of power flow control hierarchy,

generation and transmission scheduling in a deregulated

power system are governed by power market (specifically

the day-ahead market). At this level of control, there is

little distinction between ac and dc transmissions. This

means that the bids to the electricity market coupled with

power flow constraints (in both ac and dc transmissions)

will determine the market settlement and the final powerflow schedule. Similarly, in tertiary control, the original

power flow schedule is modified based upon the latest

available data about the power system including ac and dc

transmission networks.

As one goes down the control hierarchy, the distinction

between ac and dc grids becomes larger. In ac grids, power

flow is controlled by adjusting references to generating

units, whereas in dc grids, power flow is controlled byadjusting references to converter units. Like that of ac

grids, it is possible to impose a secondary control for dc

grids so that large dc voltage deviations as well as power

flow deviations can be compensated. The flow chart in

Fig. 17 describes the primary, secondary, and tertiary con-

trol sequences in a power system consisting of ac grid and

HVDC grid systems.

The secondary control in the dc grid is similar to the tie-line control in ac grid systems and has the objective of

restoring the power flow of the selected HVDC stations

back to scheduled levels after the occurrence of large

steady-state power flow deviations. As discussed in

Section IV, large power flow deviations in the dc grid

come from sudden outage of a converter station. The sim-

ulated case of wind power loss in Fig. 14 can be a good

example for steady-state power flow deviation due to anoutage of an HVDC station. In this particular case, although

Fig. 15. Primary reserves exchange via HVDC grid.

Fig. 16. Comparison of frequency responses of the RG–CE grid with

and without the frequency support by the North Sea HVDC grid.



converters 1, 2, and 4 are participating in the primary

control, there may be a more urgent need to restore power

flow in certain HVDC stations than in the others.Here we have considered a scenario where there is a

need to restore power flow in converters 1 and 2 (i.e.,

RG–GB connections) at the expense of more power

injection from the RG–N grid via converter 4. This is based

on the premise that the huge installed capacity of Norway in

the RG–N grid is capable of such provision. Based on this

scenario, the responses of the secondary control in the

meshed North Sea HVDC grid model are shown in Fig. 18.As shown in Fig. 18, the secondary control action is

capable of restoring the power flow of converters 1 and 2 to

the same level as prior to the loss of connection to offshore

wind farm. Power flow via converter terminals 3 and 5

remained intact throughout the primary and secondary

control actions.

In conclusion, the well-established knowledge on ope-

ration and market integration of ac power systems caneasily be adapted to a meshed North Sea HVDC grid.

VII. CHALLENGES IN DEVELOPINGMESHED NORTH SEA DC GRID

While the potentials of the meshed HVDC grid in the

North Sea appear to be enormous, there are challenges in

employing the technology on the ground. The most promi-

nent challenges are discussed as follows.

1) DC Fault Handing Issues: DC fault protection based

upon converters ac side protection and dc isolators has

been proposed in the literature, thereby avoiding the need

for dc circuit breakers [20]. The method involves dis-connecting all converters on their respective ac sides, then

isolating part of the dc grid with dc fault and reconnecting

all the healthy converter stations to their respective ac

grids. Although the method is capable of disconnecting

the faulty part and restoring normal operation of the rest

of the dc grid, the momentary disconnection of the entire

dc grid involved in this process could undermine security

of supply unless the restoration time is sufficiently small.DC circuit breakers on the other hand could instanta-

neously disconnect the faulty part without the need to

temporarily disconnect the dc grid from all ac connections.

However, dc circuit breakers in the high-voltage and high-

current ranges have not been commercially available yet.

2) Standardization of DC Transmission Voltage Level andRequirements for Dynamic Responses: Current suppliers ofVSC–HVDC technology use different dc voltage ratings for

HVDC solutions, which usually are specifically chosen to

suit the applications. Since a meshed HVDC grid is ex-

pected to involve various technology suppliers and trans-

mission system operators, there is a clear need for

determining standard dc voltage level as well as HVDC

terminal response requirements (such as droop level for dc

voltage control, droop level for frequency support byHVDC, responses to ac and dc faults, etc.).

3) Ambiguity Surrounding Ownership and Management ofthe North Sea Supergrid: Since the North Sea supergrid will

Fig. 17. Flow chart describing primary, secondary, and tertiary

controls of ac/dc grids.

Fig. 18. Secondary control response of the HVDC grid for loss of

connection to offshore wind farm.



most likely span several transmission system operators, it

may not be very clear who will have ownership andresponsibility for its operation. These are crucial questions

that should be addresses properly since these directly

affect sharing of investment and maintenance costs as well

as operation and market integration of the dc grid.

VIII . CONCLUSION

If the vast potential of wind energy in the North Sea is tobe fully utilized, strategies for increased security of supply

should be put in place, especially to deal with power fluc-

tuations from offshore wind farms. In this regard, a

meshed HVDC grid is an emerging technology whichVif

employed in the North Sea regionVcan potentially en-

hance the security of supply of the ac grids connected to it.

A meshed HVDC grid in the North Sea can potentially

have several benefits, which include exchange of reservesbetween RG–GB, RG–N, and RG–CE grid systems,

integration of offshore wind farms with balancing power

provision from Nordic area (particularly from Norway),

and access to wider power market areas. As a result, the

North Sea ‘‘supergrid’’ (as it is often called) can increase

security of supply as well as enable better utilization of

energy resources in the interconnected areas.

Results from simulation studies show that withappropriate control schemes, a meshed HVDC grid in

the North Sea can enhance grid frequency control and help

in dealing with outage conditions such as loss of wind

power production.

The need for fast and reliable dc fault protection as well

as ambiguity regarding ownership and management of the

meshed HVDC grid are mentioned as main challenges inthe development process of the North Sea supergrid. h

APPENDIXThe block diagrams of the various control modes of

VSC–HVDC terminals discussed in this paper are shown in

Fig. 19. In the upper parts of Fig. 19, the steady-state dc

voltage versus power characteristics are shown, and below

are the block diagrams of the corresponding controllers.

Proportional–integral (PI) controllers are used in all threecases, ensuring that the desired characteristics are ob-

tained when the error signal e is controlled to zero.

P and U refer to power and dc voltage measurements of

the VSC–HVDC terminal whereas P� and U� refer to

power reference and dc voltage reference, respectively. Rdc

is the dc voltage response constant. i�d is the reference

input for active current controller (not shown here). d�qreference-frame-based current control of VSC has beenused for the simulations in this paper. Readers are referred

to [21] for further details on the current control.

In Fig. 20, the block diagram of frequency droop

control in VSC–HVDC is shown. In Fig. 20(a), constant

power controller is supplemented with frequency droop

control, and in Fig. 20(b), the controller consists of both

dc voltage droop and frequency droop control elements. In

the simulation case of Section V-D, the controller shown inFig. 20(a) was implemented for terminal 3 (converter

connected to the RG–CE grid).

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Fig. 20. Frequency droop control provision for VSC–HVDC: (a) with

constant power control; and (b) with dc voltage droop control.



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ABOUT THE AUT HORS

Temesgen M. Haileselassie received the M.Sc.

degree in electric power engineering from the

Norwegian University of Science and Technology

(NTNU), Trondheim, Norway, in 2008, where he is

currently working toward the Ph.D. degree.

His research interests include multiterminal

HVDC, grid integration of wind farms, and control

and dynamics of power systems.

Kjetil Uhlen (Member, IEEE) received the M.S. and

Ph.D. degrees in control engineering from the

Norwegian University of Science and Technology

(NTNU), Trondheim, Norway, in 1986 and 1994,

respectively.

He is currently a Professor of Power Systems at

NTNU. His main interests are control and opera-

tion of power systems, power system dynamics,

and wind power integration.



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Power System Security in a Meshed North Sea HVDC Grid

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