AckermannTh. (ed) Wind Power in Power Systems

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Year-round analysis using the OPF tool shows that penetration levels up to 14 MW

can be achieved with virtually no energy curtailed (for a 14 MW wind farm, only

87 MWh is expected to be curtailed in one year). For a wind farm of 16 MW, the

amount of energy curtailed is 1578 MWh, or 5.3 %. Clearly, area-based voltage control

by OLTC transformers allows a considerable increase in penetration of DG. It is,

however, important to remember that this technique of vo ltage regulation will need

the implementation of a distribution management system (with appropriate commu-

nication systems).

21.3.2.7 Area-based voltage control by on-load tap-changing transformer and voltage

regulator

As indicated in Section 21.3.1, the use of OLTC voltage control in order to reduce the

voltage on the feeder where the generator is connected may produce unacceptable

voltage drops on adjacent feeders that supply loads. The separation of the control of

voltage on feeders that supply load, from the control of voltage on feeders to which the

generators are connected, is achieved by the application of voltage regulators, and this is

investigated in this section.

In order to examine the benefits of this option, a voltage regulator is inserted at the

beginning of the feeder, which accommodates the wind farm. This allows independent

voltage regulation on feeders with loads by the OLTC transformer, while the voltage

regulator controls the voltage on the feeder with the wind farm. In the OPF, the voltage

regulator is modelled in a similar way as an OLTC transformer with the ability to

change the turns ratio from 0.9 p.u. to 1.1 p.u. continuously. The results of this case are

shown in Figure 21.7. It is clear that this voltage control policy increases the amount of

generation that can be connected (up to 20 MW) with almost no curtai led energy.

5000

10000

15000

20000

25000

000

35000

40000

4 6 8 101214161820

Embedded wind

eneration penetration (MW)

Energy (MWh)

Generation curtailed

Net generation

Figure 21.6 Energy generated and curtailed with the application of on-load tap-changing

(OLTC) transformer area-based voltage control

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21.3.2.8 Impact of voltage controls on losses

Connection of distributed generators alters the loss performance of distribution net-

works. A low level of penetration of DG tends to reduce network power flows and thus

network losses. However, when penetration is high then DG will export power to the

grid and may cause increased losses. In this particular system, with no generation being

connected, network losses are 2860 MWh per year. Figure 21.8 shows the change in

network losses for various levels of penetration and various voltage control strategies.

For a low level of penetration, losses are reduced regardless of voltage control. For the

000

10000

000

20000

000

35000

40000

4 6 8 10 12 14 16 18 20

Embedded wind

eneration penetration (MW)

Energy (MWh)

Generation curtailed

Net generation

Figure 21.7 Energy generated and curtailed energy from a wind farm over a year, for different

values of wind farm penetration

–500

500

1000

1500

2000

2500

4 6 8 101214161820

Embedded wind generation penetration (MW)

Loss (MWh)

Power factor = 0.98

Power factor = 0.95

SVC (3 MVAR)

OLTC

OLTC and VR

Figure 21.8 The losses for different voltage controls and distributed wind generation penetra-

tion. Note: use of static VAR compensator; OLTC ¼ use of on-load tap-changing transformer;

VR ¼ use of voltage regulator

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higher level of penetration, made possible by the application of OLTC transformers and

voltage regulators, losses are signifi cant because of the increased amount of renewable

energy generated.

21.3.2.9 Economic evaluation

The development of DG will depend on governments’ environmental actions, deregula-

tion, novel technologies and economics. Amongst these fact ors, economics are likely to

be decisive for the selection of future technologies and policies. Therefore, an economic

evaluation of DG is indispensable. A cost–benefit analysis (CBA) enables an evaluat ion

and comparison of the cost-effectiveness of projects. Monetary values are placed on

costs and benefits to find out whether the benefits outweigh the costs. The CBA used for

the studies here takes into account: capital costs; operation, maintenance and repair

(OM&R) costs; costs of active management schemes; savings from economies of scale;

and revenue from energy sales and environmental incentives. Based on an assumed

discount rate and a useful plant life time, an evaluation and compari son of net present

values (NPVs) of alternative projects can be carried out. A positive NPV indicates that a

project tends to be profitable.

The overall benefits of the studied active management schemes are summarised in

Figure 21.9 for various levels of DG penetration. The studies performed clearly show

NPV (p.u.)

468101214161820

Connected DG capacity (MW)

GC, PF = 0.98

GC, PF = 0.95

OLTC

OLTC + VR

SVC (3 MVAR)

Figure 21.9 Comparison of net present values (NPVs) of active management schemes. Note:

NPV of 6 MW care is taken to represent 1 p.u.; DG ¼ distributed generation; GC ¼ generation

curtailment; PF ¼ power factor; SVC ¼ use of static VAR compensator; OLTC ¼ use of on-load

tap-changing transformer; VR ¼ use of voltage regulator

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significant benefits of the use of active control in the distribution network. The most

beneficial are schemes with area-based voltage control by OLTC transformers and

voltage regulators, achieving a threefold increase in the cap acity of DG that can be

connected.

The aim of the economic evaluation was to investigate the optimum combination

of plant capacity and the applied active management scheme. The export capacity of

the plant was varied from 4 MW to 20 MW. Five active management schemes were

studied. Thes e included generation curtailment (GC) with power factors (PFs) 0.98

and 0.95, 3 MVAR reactive compensation, and OLTC transformer voltage control

schemes without voltage regulators (labelled OLTC) and with voltage regulators

(labelled OLTC þVR). The NPVs of all cases studied were calculated. Positive NPVs

represent overall benefit. The NPV of 6 MW DG represents the maximum DG export

capacity that does not require netwo rk reinforcement or active management. It is

therefore taken as the reference, 1 p.u. NPVs greater than 1 p.u. result from increased

income streams that outweigh the costs of active management and additional plant

capacity. Maximum NPVs, as depicted in Figure 21.9, indicate the optimum DG

plant capacity and active management scheme combinations. In this study, all five

active management schemes enable increased energy exports but have different tech-

nical and economic limits:

Generation curtailment with a power factor of 0.98: this has its highest NPV at

around 8 MW, but if 13 MW capacity is exceeded it becomes unprofitable.

Generation curtailment with a power factor of 0.95: this reaches its highest NPV at

around 10 MW and seems to be profitable up to around 17.5 MW. Note therefore that

higher energy exports are possible at the expense of a decrease in power factor. The

difference between both curves quantifies the financial benefit of a de creased power

factor. The resulting costs such as cost of network losses and charges for reactive

power are not considered in the NPV calculation.

Use of SVC (3 MVAR): this shows almost the same characteristic as generation

curtailment with a power factor of 0.95. The benefi t of SVC application in networks

with a higher X/R ratio is expected to be higher than in this example with a relative

low X/R ratio.

Use of an OLTC transformer: this scheme has its highest NPV at around 14 MW, but

higher DG capacities, up to 20 MW, are still economically feasible.

Use of an OLTC transformer and voltage regulators: benefi t of voltage regulator

application can be perceived in particular for DG capacities exceeding the point of

best performance (14 MW) of the OLTC scheme, being quantified as the difference

between the OLTC and OLTC þ VR curves in Figure 21.9.

To access man y of these benefits new commercial arrangements have to be developed,

and techniques must be established that allow one to determine the positive or negative

contribution of all network participants.

The paradigm shift in energy generation, transmission and distribution will also result

in costs, but it is expected that active management has the potential to reduce these co sts

compared with conventional system reinforcement. The cost of active management

equipment seems often to be lower than the cost for additional transformers, cables

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and overhea d lines. That is why active management control schemes can be a competi-

tive alternative to conventional system reinforcement with regard to mitigating the

voltage-rise effect.

21.3.2.10 The benefits of active management

In this section the benefits of active distribution management have been quantified in

terms of the amount of the additional capacity of DG that can be connected to the

existing distribution system. The benefits of the studied active management control

strategies have been quantified by the volume of annual energy produced and the

corresponding revenue that can be generated for various capacities of wind generation

installed.

However, the added value of the active management of distribution networks is

multifaceted. The benefits of active management are not limited to the facilitation

of higher penetration of DG in existing networks or to the reduction of connection

costs through the maximisation of the use of existing networks. For instance,

energy generated close to demand is considered to have a higher value because of

reduced network losses and avoided utilisation of upstream network assets. Another

potential benefit of active management is the provision of services. It can enable

DG to provide ancillary services (e.g. reactive power management) and provide

network support (contributing to security of supply) to the distribution network.

However, the distribution network operator could provide the service of active

management, to yield higher profits for DG as a result of increased energy output.

The prices and the commercial arrangements for such services are yet to be estab-

lished and therefore they are difficult to value at present. Other benefits of active

management lie in its potential to defer or to reduce investment in distribution

plants (e.g. in voltage control and peak demand shaving). A benefit associated with

reduced investment is a lower risk with respect to stranded assets as a result of

potential load or generation migration. In future, active distribution networks may

enable islanded operation, and this could increase the quality of service delivered by

distribution networks. At present, it is difficult to quantify such benefits of active

management and distributed generation since a considerable amount of judgement

is required.

Value assessment methodologies must be capable of reflecting technical and economic

impacts. One possible approach to identify and quantify the benefit of DG islanding in a

portion of the distribution network normally connected to the grid is a cost–benefit

assessment approach based on the customer outage cost methodology (Kariuki and

Allan, 1996a, 1996b). This approach would assess the value of DG islanding to con-

sumers. The benefit of DG islanding in future active distribution networks can be seen

as offering an improved quality of service to customers. The monetary value of the

improved quality of service can be determined as a reduction in customer outage costs

in a service area. Figure 21.10 shows how reduced system outage durations as a result of

DG islanding results in reduce d customer outage costs. In order for islanding to

be viable, the identified value or benefit must outweigh the costs of making islanded

operation possible.

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21.4 Conclusions

This chapter described the principles of active management of distribution networks.

The main benefits of active management were identified and illustrated in worked

examples. Four active management schemes were studied: (A) use of active power

generation curtailment, (B) use of reactive power management, (C) use of area-based

coordinated volta ge control of OLTC transformers and (D) the application of voltage

regulators. The studies performed clearly showed significant benefits regarding the

active co ntrol of distribution networks. It was shown that a considerable increase in

penetration levels can be achieve d when distributed generators are allowed to absorb

reactive power. The use of OLTC transformer voltage control appears to be most

beneficial as it allows for a large increase in penetration at a low cost, from the primary

plant perspective, but would require more complex control of distribution network

operation. An increase in DG based on these controls would be conditioned by the

operation of an adequate ancillary services market. Further benefits of active manage-

ment were discussed, and one methodology to assess the value of DG islanding was

presented. It can be concluded that the exploitation and assessment of the benefits of

active management often depend on the development of appropriate technical informa-

tion tools and commercial arrangements. These arrangements and frameworks must

consider the requirements of an unbundled electricity industry and must allow the

marketing of such benefits.

References

[1] Bopp, T., Shafiu, A., Chilvers, I., Cobelo, I., Jenkins, N., Strbac, G., Haiyu, L., Crossley, P. (2003)

‘Commercial and Technical Integration of Distributed Generation into Distribution Networks’, presented

at CIRED, 17th International Conference on Electricity Distribution.

[2] Jenkins, N., Allan, R., Crossley, P., Kirschen, D., Strbac, G. (2000) IEE Power and Energy Series: 31.

‘Embedded Generation’, Institute of Electrical Engineers (IEE), London.

[3] Kariuki, K. K., Allan, R. N. (1996a) ‘Evaluation of Reliability Worth and Value of Lost Load’, IEE Proc.

Gener. Transm. Distrib. 143(2) 171–180.

Customer outage costs

Outage duration

Benefit

Without islanding With islanding

Figure 21.10 Reduced customer outage cost resulting from islanding of distributed generation

476 Benefits of Active Management of Distribution Systems

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[4] Kariuki, K. K., Allan, R. N. (1996b) ‘Application of Customer Outage Costs in System Planning, Design

and Operation’, IEE Proc. Gener. Transm. Distrib. 143(4) 305–312.

[5] Liew, S. N., Strbac, G. (2002) ‘Maximising Penetration of Wind Generation in Existing Distribution

Networks’, IEE Proc. Gener. Transm. Distrb. 149(3) 256–262.

[6] Masters, L., Mutale, J., Strbac, G., Curcic, S., Jenkins, N. (2000) ‘Statistical Evaluation of Voltages in

Distribution Systems with Wind Generation’, IEE Proc. Gen. Trans. Dist 147(4) 207–212.

[7] Saad-Saoud, Z., Lisboa, M., Ekanayake, J., Jenkins, N., Strbac, G. (1998) ‘Application of STATCOM to

Wind Farms’, IEE Proc. C, Gen. Trans. Dist. 145(5) 511–516.

[8] Strbac, G., Jenkins, N., Hird, M., Djapic, P., Nicholson, G. (2002) Integration of Operation of Embedded

Generation and Distributed Networks, UMIST, Manchester, and Econnect, Future Energy Solutions,

publication K/EL/0262/00/00.

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Transmission Systems for

Offshore Wind Farms

Thomas Ackermann

22.1 Introduction

The interest in the utilisation of offshore wind power is increasing significantly world-

wide. The reason is that the win d speed offshore is potentially higher than onshore,

which leads to a much higher power production. A 10 % increase in wind speed results,

theoretically, in a 30 % increase in power production. The offshore wind power poten-

tial can be considered to be significant. For Europe, the theoretical potential is esti-

mated to lie between 2.8 and 3.2 PWh (Germanischer Loyd, 1998) and up to 8.5 PWh

(Leutz et al., 2001). In addition, countries in central Europe, particularly Germany, are

running out of suitable onshore sites. Some countries promote offshore wind power

because they believe that offshore wind power can play an important role in achieving

national targets for the reduction of emissions of carbon dioxide (CO

). However,

investment costs for offshore wind power are much higher than those for onshore

installations. Fortunately, in many central European waters, water depth increases only

slowly with distance from the shore, which is an important economic advantage for the

application of bottom-mounted offshore wind turbines.

Until now, practical experience from offshore wind energy projects is limited (for an

overview of existing projects, see Table 22.1). The installation and supporting structure

of offshore wind turbines is much more expensive than that of onshore turbines. There-

fore offshore wind farms use wind turbines with a high rated capacity ( 1:5MW),

which are particularly designed for high wind speeds. The first offshore projects materi-

alised in Denmark, the Netherlands, Sweden, the United Kingdom and Ireland. Most

existing offshore wind farms tend to be demonstration projects close to the shore.

Wind Power in Power Systems Edited by T. Ackermann

Ó 2005 John Wiley & Sons, Ltd ISBN: 0-470-85508-8 (HB)

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However, a shift towards large-scale commercial projects has already begun. At the time

of writing, the largest existing projects are the two Danish wind farms: Horns Rev, with

80  2 MW (160 MW) and Nysted, with 72  2:3 MW (165:6 MW).

Further offshore projects are in the planning stage, particularly in Denmark,

Germany (with proposals for a total of 60 GW!), the Netherlands, France, the United

Table 22.1 Offshore wind energy projects, as of 31 January 2003

Name and Location Year No.

turbine

Rated

capacity

(MW)

Total

capacity

(MW)

Hub

height

(m)

Minimum

distance

from

shore (km)

Water

depth

(m)

Nogersund, Sweden

1991 1 0.22 0.22 37.5 0.25 6

Vindeby, Baltic Sea,

Denmark

1991 11 0.45 4.95 37.5 1.5 2–5

Lely, Ijsselmeer, The

Netherlands

1994 4 0.5 2 41.5 0.80 5–10

Tunø Knob, Baltic

Sea, Denmark

1995 10 0.5 5 43 6.0 3–5

Irene Vorrink,

Ijsselmeer, The

Netherlands

1996 28 0.6 16.8 50 0.02 1–2

Bockstigen, Baltic

Sea, Sweden

1997 5 0.55 2.75 41.5 4.0 5–6

Lumijoki/Oulu,

Baltic Sea, Finland

1999 1 0.66 0.66 50 0.5 2–3

Utgrunden, Baltic

Sea, Sweden

2000 7 1.425 9.975 65 8.0 7–10

Blyth, North Sea, UK 2000 2 2.0 4 58 1.0 6–9

Middelgrunden Baltic

Sea, Denmark

2001 20 2.0 40 60 2–3 3–6

Yttre Stengrund,

Baltic Sea, Sweden

2001 5 2.0 10 60 5.0 6–10

Horns Rev, Denmark 2002 80 2.0 160 80 14.0 6–12

Frederikshaven,

Baltic Sea, Denmark

2002 2

2.3

7.6 80 0.5 1

Rønland, Denmark 2002 4 2 17.2 70 0.5 2–3

4 2.3

Samso, Baltic Sea,

Denmark

2003 10 2.3 23 61 3.5 20

Nysted, Baltic Sea,

Denmark

2003 72 2.3 165.6 68 6–10 6–9.5

North Hoyle, UK 2003 30 2.0 60 80 7–8 12

Arklow Bank,

Republic of Ireland

2003 7 3.6 25.2 73.5 10 5–15

Decommissioned in 1998.

480 Transmission Systems for Offshore Wind Farms