Value of Fault Ride Through capability of Wind generation in UK.pdf

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Centre for Distributed Generation and

Sustainable Electrical Energy

Value of fault ride through capability

of wind generation in the UK

Summary report

T. Bopp and Prof G. Strbac

PO Box 88, Manchester, M60 1QD

October 2004



Value of fault ride through capability of wind generation in the UK

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Table of Contents

TABLE OF CONTENTS........................................................................................................ 2

EXECUTIVE SUMMARY..................................................................................................... 3

LIST OF FIGURES................................................................................................................. 7

LIST OF TABLES................................................................................................................... 7

1. INTRODUCTION............................................................................................................... 8

2. OBJECTIVES AND OVERVIEW OF THE APPROACH........................................... 11

MODELLING OF TECHNICAL AND ECONOMIC SYSTEM PERFORMANCE.................................................12

3. QUANTIFICATION OF THE VALUE OF FAULT RIDE THROUGH

CAPABILITY................................................................................................................... 18

STUDIED SCENARIOS...........................................................................................................................22

4. SENSITIVITY ANALYSIS.............................................................................................. 26

TOTAL INSTALLED WIND GENERATION CAPACITY OF 15GW .................................................... ..........26 GOVERNOR DROOP SETTING 2% ....................................................... .................................................. 27 I NERTIAL EFFECT OF WIND GENERATION ............................................................................................27

5. CONCLUSIONS ............................................................................................................... 28

6. REFERENCES.................................................................................................................. 30




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Executive summary

Although penetration of intermittent renewable resources and other forms of

distributed generation by 2020 and beyond, as described in the Energy White

Paper, may displace a significant amount of energy produced by large

conventional plant, there are concerns associated with the ability of these newgeneration technologies to withstand various disturbances and to provide

adequate system support services to ensure system security.

The design characteristics of conventional thermal and hydro generators

enable the plant to contribute to the provision of system support services

(dynamic voltage and frequency regulation) that is critical for a stable

operation of the system. Wind generation uses different technology from

conventional plant and generally, at the moment, is not able to provide a

similar range of support services to the system. At relatively low levels of

penetration this can usually be tolerated. However, operating the system withlarge amounts of such plant could pose major challenges in terms of sustaining

system integrity.

Hence, transmission network operators have recently set out a proposal that

specifies requirements for connecting of wind generation equipment to the

transmission network and these are detailed in the Grid Code consultation

document [NGC, SHETL, SPT, 2004]. In a number of countries, Grid Codes

have been reviewed to reflect the trend of increased levels of penetration of

wind generation. In addition to frequency and voltage control, communication,

dispatch, etc., one of the key issues is associated with the ability of this plantto maintain stable operation during faults on the transmission network, in

order to avoid widespread tripping of wind generation and loss of substantial

amounts of active power generation. This is known as fault ride through

capability.

In contrast to the current Grid Code proposal that demands mandatory fault

ride through capability for wind generation, this study examines the

consequences of increased levels of maximum credible instantaneous loss of

generation (from the current level of 1320MW), that is driven by the inability

of wind generation to withstand close by faults.

The primary objective of this investigation is to estimate the order of

magnitude of additional system cost that would need to be incurred in order to

accommodate wind generation of varying degree of the capability to withstand

faults on the UK transmission network. In other words, the analysis provides




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estimates of the value of various degrees of the wind turbine generator fault

ride through capability1.

In order for conventional plant to provide frequency response it must run part

loaded. Thermal units operate less efficiently when part loaded, with anefficiency loss of between 10% and 20%. In addition, in order to establish

feasibility of system operation, it will occasionally be required to curtail wind

generation2. This curtailed wind energy will need to be compensated by an

equivalent increase in the output from conventional plant, which will lead to

increase in fuel cost.

The cost associated with accommodating wind generation that is not fully

capable to ride through faults will therefore be composed of:

(i) Additional response cost, mainly fuel cost due to running the

conventional plant at lower efficiency and

(ii) Additional fuel cost due to the substitution of conventional generation

for wind generation curtailment, that occasionally may be necessary to

maintain the feasibility of system operation

Furthermore, operating an increased number of generators part loaded and

having to curtail some of wind generation will increase CO2 emissions.

To assess the cost and CO2 performance of the future UK generation system

we developed a simplified generic model of the system primary response

characteristics3 with 10GW of installed wind generation capacity. The analysis

involved a number of year round simulations of system operation necessary to

capture variations in wind and demand and to quantify the impact of key

factors, such as the degree of wind generation robustness, flexibility of

conventional generation system and the level of penetration of wind.

We estimated the additional cost to vary in the range of £14m to £21m per

annum in case the system is required to withstand loss of up to 5% of wind

1

This work adopts a cost based approach and it does not deal with Renewable Obligation issues andthe present arrangements for the provision of ancillary services and cost recovery mechanisms within NETA.2

The system will need to deal with losses of wind generation in addition to losses of conventional plant. Situations when low load conditions coincide with high outputs of wind will be most difficult todeal with. Clearly, the higher the wind output, the greater the need is for frequency response (due to theincrease in the amount of generation that may be lost). On the other hand, system inertia would tend to

be reduced during low load conditions, which will increase the speed of the initial frequency drop andmake the frequency containment task more demanding. Occasionally, the system will not be able to provide frequency response sufficiently fast and some wind generation will have to be curtailed.3 This analysis is based on the assumption that primary response service is provided by generation. Wehave excluded the contribution that frequency sensitive load disconnection can make in this context.




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generation in addition to the loss of conventional plant between 1000MW and

1320MW4 (this would correspond to the case of relatively robust but not fully

fault ride through capable plant). For potentially larger generation losses of up

to 30% of wind output (less robust wind generation) these additional costs

were found to be between £106m and £155m per annum.

The amount of wind generation curtailment for the potential instantaneous loss

of 30% of the total wind output was found to be less than 3% of the total

annual wind production, in the case of a partially flexible generation system.

Additional CO2 emissions were estimated to vary between about 0.5Mt and

4.5Mt per annum, depending on the degree of robustness of wind generators.

The results of a survey presented in the Grid Code consultation document[NGC, SHETL, SPT, 2004] suggest that the cost of equipment associated with

providing fault ride through capability is between 1% and 3% of the turbine

cost. This indicates that the cost of providing fault ride through capability is

likely to be lower than the associated value quantified in this study,

particularly if a large proportion of wind generation (more than 20%) can be

lost due to a fault on the transmission network. In other words the analysis

suggests that it would be cost efficient to invest in the equipment and solutions

necessary to enable wind generators to ride through faults, as demanded by the

proposed Grid Code. However, for reasonably robust wind generation

technology (if no more than 5% of wind output could be lost after a critical

fault on the network) the additional system cost seems to be similar to the costof developing wind turbine generators with the full fault ride through

capability.

If however more wind generation is to be installed with relatively low

robustness (if 20% or more of wind output can be lost due to a critical fault on

the transmission network) the overall system cost increase considerably, and

the case for enforcing Grid Code requirements would be even stronger. We

have quantified the additional costs for systems with 10GW and 15GW of

installed wind generation capacity.

Finally, the benefit of wind generation providing inertial effects was

estimated. Across the various cases considered, it was found that the primary

response cost could be reduced by 10% to 30% of the corresponding base case

cost. This is considered to be significant and this question should be

4Using our model we estimated the base level annual cost of response to be in order of £65m per year,

which is sufficiently close to the current response related expenditure, given that this study isconcerned with the additional cost.




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investigated further. It should be noted however that the proposed Grid Code

does not address plant inertia and that there is no incentive for its provision.

Overall, the work carried out clearly demonstrates that, if a significant amount

of wind generation with relatively low robustness is to be installed (with morethan 10% of wind generation output contributing to the maximum credible

loss), this would lead to a very considerable increase in system costs. These

additional costs would be significantly higher than the expected cost of

engineering necessary to provide fault ride through capability. The results of

the studies performed suggest that requiring sufficient fault ride through

capability for large wind farms would be economically efficient.

On the other hand, for connecting wind generation with relatively high

robustness (with less than 5% of wind output contributing to the maximum

credible loss) the increase in system cost was found to be in the same order of magnitude as the expenditure required to enable fault ride through capability.

However, in order to establish the implications of this more precisely, further

studies would be required with actual locations that may need to be restricted

and sizes of wind farms to be considered, including potential consideration of

inertial effects. Furthermore, it would be appropriate to consider the technical

and commercial potential of the demand side to provide increased volumes of

response services.




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List of Figures

FIGURE 2-1: FREQUENCY REGULATION SERVICES (FROM NGT SYS) .................................... 12 FIGURE 2-2: GENERIC SYSTEM TO MODEL PRIMARY FREQUENCY RESPONSE ......................... 14 FIGURE 2-3: PRIMARY RESPONSE CHARACTERISTICS FOR DIFFERENT DROOP SETTINGS........ 15

FIGURE 3-1: GROSS DEMAND PROFILE .................................................................................... 18 FIGURE 3-2: WIND OUTPUT PROFILE ....................................................................................... 18 FIGURE 3-3: PRIMARY RESPONSE REQUIREMENT CURVES ...................................................... 20 FIGURE 3-4: MARGINAL COST OF ELECTRICITY AND INCREASE IN CO2 EMISSIONS................ 22

List of Tables

TABLE 3-1: ADDITIONAL ANNUAL PRIMARY RESPONSE COST ................................................ 23 TABLE 3-2: WIND GENERATION CURTAILED ........................................................................... 23 TABLE 3-3: ADDITIONAL ENERGY COST DUE TO WIND GENERATION CURTAILMENT ............. 24

TABLE 3-4: ADDITIONAL CO2 EMISSIONS DUE TO ADDITIONAL PRIMARY RESPONSE PROVISION............................................................................................................................. 24 TABLE 3-5: ADDITIONAL CO2 EMISSIONS DUE TO WIND ENERGY CURTAILMENT................... 24 TABLE 3-6: ADDITIONAL COST OF FAULT RIDE THROUGH CAPABILITY .................................. 25 TABLE 4-1: PERCENTAGE INCREASE IN ADDITIONAL PRIMARY RESPONSE COST .................... 26 TABLE 4-2: CURTAILED WIND ENERGY AND NUMBER OF HALF HOURLY CURTAILMENT

PERIODS................................................................................................................ 26




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1. Introduction

1.1. An overriding objective in the operation of power systems is to maintain

security as widespread system blackouts are very costly and extremely

damaging for society. The technical performance of the generating plant,

particularly at times when the system experiences disturbances, plays a critical

role in maintaining system integrity. The design characteristics of

conventional thermal and hydro generators enable the plant to contribute to

the provision of system support (dynamic voltage and frequency regulation)

that is critical for a stable operation of the system.

1.2. An appropriate level of frequency regulation services (primary and secondary

response) and reserve capability are necessary to deal with disturbances

caused by outages of generators. Services related to system support are

provided through a mix of compulsory services (such as frequency responseand reactive support) defined by the Grid Code, and a spectrum of commercial

services (such as enhanced response service and standing reserve).

1.3. Although penetration of intermittent renewable resources and other forms of

distributed generation by 2020 and beyond, as described in the Energy White

Paper, may displace a significant amount of energy produced by large

conventional plant, there are concerns associated with the ability of these new

generation technologies to withstand various disturbances and to provide

adequate system support services to ensure system security.

1.4. Wind generation uses different technology to conventional plant and

generally, at the moment, is not able to provide a similar spectrum of support

services to the system. At relatively low levels of penetration this can usually

be tolerated. However, operating the system with large amounts of such plant

could pose major challenges in terms of sustaining system integrity.

1.5. Hence, transmission network operators have recently set out a proposal that

specifies requirements for connecting of wind generation equipment to the

transmission network and these are detailed in the Grid Code consultationdocument [NGC, SHETL, SPT, 2004]. In a number of countries, Grid Codes

have been reviewed to reflect the trend of increased levels of penetration of

wind generation.

1.6. In addition to frequency and voltage control, communication, dispatch, etc.,

one of the key issues is associated with the ability of wind generation to

maintain stable operation during faults on the transmission network, in order

to avoid widespread tripping of wind generation and losses of substantial




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amounts of active power generation. This is known as the fault ride through

capability. Quantification of the value of fault ride through capability of wind

generation in the future UK electricity system is the main subject of this

report.

1.7. For the duration of a fault on the transmission network, the voltage on the

faulted phases is assumed to be zero at the point of fault. Considering

relatively low transmission circuit impedances, such fault conditions can

cause a large transient voltage depression across wide network areas.

Conventional synchronous generators are expected to trip only if a permanent

fault occurs on the circuit they are directly connected to. However, other

electrically nearby generators that are connected to healthy circuits will

remain connected and stable after the faulted circuits are disconnected. At

present, the transmission system is operated to withstand a maximum sudden

or instantaneous infeed loss of 1320 MW (Sizewell B).

1.8. However, if the generation connected to healthy circuits would not remain

connected and stable during and after the fault is cleared, this generation will

be lost in addition to that disconnected by the original fault (up to 1320MW of

generation, conventional or renewable). Clearly, in this case the system would

be exposed to a loss of generation greater than the current maximum.

1.9. Conventional synchronous generating technology is capable of continuing to

operate through the transient voltage depression that accompanies secured

system fault events. Therefore, only generators connected to the faultynetwork section will be disconnected by protection actions and the fault will

not cause the coincident loss of synchronous generators connected to healthy

network sections. The transmission system is operated on this basis, and the

fault ride through requirement is designed to ensure that the existing level of

necessary resources is maintained to provide stability and security of the

system.

1.10. On the other hand, simple wind turbine technology including its dynamic

performance driven by the generator control design, does not readily possess

similar levels of robustness and could be susceptible to tripping if the voltagetransiently falls below a minimum level. This minimum transient voltage that

can be sustained (given the corresponding fault clearance time) is important,

as it would drive the amount of generation that would be lost for each

particular fault location (and system configuration). The lower the minimum

voltage that can be sustained is, the smaller the area affected by the fault

would be, and hence the lower the amount of generation that would be lost. A

number of studies [NGC, SHETL, SPT, 2004; Tyndall, 2003] have been




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carried out to determine the depth of the propagation of voltage depressions

for various fault locations and generation scheduling patterns5.

1.11. In summary, if the wind generation to be connected were not able to ride

through faults in a similar manner as conventional synchronous plant, thesystem would be exposed to a loss of generation greater than the current

credible maximum. In this context, the proposed Grid Code update to

incorporate wind generation, is based on the fundamental requirement that the

maximum largest loss of generation should not exceed 1320MW. This

effectively requires that wind generation must remain connected and be able

to ride through faults on the transmission network.

1.12. The impact of increased levels of instantaneous generation loss, driven by the

inability of wind generation to withstand close by faults, on system cost and

CO2 emissions is investigated in this study.

5Also, a factor to be considered is the amount of wind generation connected, as this may have an

impact on the actual level of transient voltage at the terminals of the generator due to voltage difference between the fault and the wind farm.




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2. Objectives and overview of the approach

Objectives

2.1. The primary objective of this study is to estimate the order of magnitude of

additional system cost that would need to be incurred in order toaccommodate wind generation with various degrees of robustness to withstand

faults on the UK transmission network. In other words, the analysis provides

estimates of the value of various degrees of the capability of wind turbine

generators to ride through faults on the transmission network.

2.2. For this purpose, we have developed a generic dynamic generation system

model to examine technical, economic and environmental performance of the

UK system operating with significant amount of wind generation (10GW and

15GW). This includes implicit modelling of different degrees of ability of

wind turbine generators to ride through to faults. This operation will requireadditional frequency regulation resources to be made available to enable the

system to cope with losses of generation significantly above the current

maximum instantaneous infeed loss of 1320MW. Respecting the physical

limits regarding the amount of generation loss that the system can handle in

this study, we quantify the additional fuel cost and CO2 emissions associated

with providing increased levels of frequency regulation services6.

2.3. The results of this work should also inform the debate associated with the

current Grid Code review in the UK. The current proposal includes a

mandatory fault ride through capability requirement into the Grid Code tokeep the maximum credible loss of generation at the present level (1320MW),

whereas this study examines the consequences of increased levels of

instantaneous generation losses, driven by the inability of wind generation to

withstand faults on the transmission network.

2.4. If a cost reflective pricing of frequency response were to be established, fault

ride through incapable plant would be responsible for the additional cost

required to provide increased levels of frequency response. In this case, the

operators of such plant would have a choice to either invest in fault ride

through capability or to cover the cost of increased frequency responserequirements. Furthermore, there may be times when the output of fault ride

through incapable plant would need to be preventively curtailed to ensure that

the maximum credible loss that the system can handle does not exceed its

physical limits. In this context, the study should enable the cost effectiveness

of the proposed Grid Code solution to fault ride through to be investigated.

6 This analysis is based on the assumption that primary response service is provided by generation. Wehave excluded the contribution that frequency sensitive load disconnection can make in this context.




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Modelling of technical and economic system performance

Frequency Response: Background

2.5. Frequency is managed by a combination of a) continuous and b) occasional

response services. These two services are illustrated in Figure 2-1.

Figure 2-1: Frequency regulation services (from NGT SYS)

2.6. Continuous response is provided by generation equipped with appropriate

governing systems that control their outputs to neutralise the frequencyfluctuations that may arise from relatively modest changes in demand and

generation. Traditionally, large synchronised generators instructed to operate

in frequency sensitive mode have provided this service.

2.7. The objective of occasional response is to contain significant and abnormal

frequency excursions caused by sudden mismatches in the generation/demand

balance e.g. loss of generation. Primary frequency response requires the most

rapid generator response. The generators must be capable of increasing their

active power output within 10 seconds of predefined system frequency

excursions, and be capable of maintaining this response for a further 20seconds. Generators that provide secondary frequency response services must

be capable of increasing their active power output within 30 seconds of

predefined system frequency excursions, and be able to maintain this response

for a further 30 minutes [Johnson, 1998; NGC GC, 2004]7.

7 The concept of primary and secondary response is devised for steam plant and this distinction is lessrelevant for gas fired plant.




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2.8. The system frequency drops sharply following a sudden loss of generation, as

illustrated in Figure 2-1. The rate of change of the frequency deviation

following the loss of generation is proportional to the magnitude of the loss

and inversely proportional to the kinetic energy stored in the power system.

This initial rate of frequency change df/dt can be calculated in accordance to

Equation 2-1 (∆ P denotes the amount of generation lost and E kinetic stands for the stored kinetic energy of the power system considering generation and

demand side).

kinetict

pu

E

P

dt

df

×

∆=

= 20

(2-1)

2.9. Given that the kinetic energy stored in the system is proportional to the

amount of rotating machines on the system, the most critical condition will be

at times of low demand. Assuming the existing limit of 1320MW for the

maximum credible loss of generation and assuming an average inertia

constant of H = 6 seconds, the maximum initial rate of the frequency drop,

observed during minimum load conditions (e.g. 20GW), would amount to

0.275Hz/s. Clearly, by increasing the loss of generation, the rate of change of

the frequency deviation will increase; and the time available for frequency

response to develop and to contain the frequency drop will reduce. Generators

operating in frequency sensitive mode (including load disconnections

triggered by low frequency relays) would need to react sufficiently fast not to

allow the frequency to drop below 49.2Hz (see Figure 2-1).

2.10. On the other hand, inertial effect decelerates the rate of change of the

frequency fall. As currently doubly fed induction generation based wind

turbines do not produce inertial effects this will have an adverse impact on the

system frequency performance and increase the need for frequency response

services.

Description of the model

2.11. To study the performance of the UK generation system, we developed ageneric model of the system primary response characteristics. The model is

used to estimate the maximum loss that the system can withstand and the

corresponding response requirement. The single busbar governor-turbine-

power system model shown in Figure 2-2 is used. All generators are modelled

as one lumped generator and the loss of generation is modelled as a

superimposed load change.




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Figure 2-2: Generic system to model primary frequency response

2.12. Following a sudden loss of generation, the frequency will start falling (∆ f ), andthe rate of change of frequency will be determined by the system’s inertia. We

also included the positive effects of frequency sensitive load (D). The droop

settings (R eq) of the governors will dictate the need for the increase in the

generators’ active power output. However, the speed of the reaction of the

governor and turbine will be driven by the values of their respective time

constants (T). The value of these time constants will drive the delay in the

response of the generators. Finally, the increase in generators active power

output will not only reduce the rate of change of the frequency drop but will

contain the frequency fall and eventually increase the system frequency.

2.13. The frequency response characteristic of generators i.e. the rate of change and

magnitude of the active power increase has a significant impact on the

magnitude and the time of the frequency dip. Figure 2-3 shows primary

response curves simulated for a frequency change of –0.8Hz and droop

settings of 2%, 3% and 4%. The rate of change and the magnitude of active

power provision and the inertia constant of the power system are the decisive

factors that determine the maximum loss of generation that the system can

handle.




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Figure 2-3: Primary response characteristics for different droop settings

2.14. The parameters of the model have been chosen to reproduce frequency

profiles observed on the system.

Expected generation loss

2.15. The expected maximum loss that the system is required to withstand will

depend on the actual operating condition of the system, i.e. on the maximum

amount of conventional and wind generation that can be lost as a consequence

of faults. We therefore modelled various levels of fault ride through capability

of wind generation by introducing the wind power loss factor (WPLF) that

presents the proportion of the actual wind generation that will be disconnected

in case of a critical fault. We studied a system with 10GW of wind installed

and considered WPLF up to 30%.

2.16. Given the fluctuations in wind power output in time, the amount of generation

that would be actually lost will also vary. Hence when determining the amount

of response required, variations in wind and demand conditions need to be

taken into account. We have therefore carried out year round studies to

estimate the additional annual cost of providing an increased amount of

response necessary to accommodate 10GW of wind generation with various

WPLFs corresponding to different levels of wind generation robustness.




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2.17. Most critical conditions arise when low demand coincides with maximum

wind generation. During these conditions, a significant portion of demand will

be met by wind generation and leaving little room for conventional

generation. Consequently, the system frequency response capability will be

reduced (assuming that only conventional generation would provide this

service). Assuming that wind generation does not provide inertial effects, the

system’s inertia will be reduced, causing the frequency to fall relatively fast in

case of plant outages. On the other hand, the magnitude of potential

generation loss to be managed will be relatively high in these situations as the

amount of wind generation that can be lost would be proportional to the wind

generation output.

2.18. In the extreme, the condition can arise in which the demand for primary

response exceeds the system primary response capability. To maintain the

feasibility of system operation in such a situation, fault ride through incapable

wind generation must be curtailed to reduce the maximum credible loss and,

consequently, the primary response requirement. At the same time more

conventional generation would be brought onto the system to meet the energy

balance. This will increase the system inertia and the primary response

capability. These effects were taken into account when determining the

minimum amount of wind energy that may need to be curtailed to maintain

feasibility of system operation.

Additional system cost and CO2 emissions

2.19. It follows from the above discussion that in order to deal with the increased

generation losses driven by fault ride through incapable wind generation, the

system will need to provide for increased amounts of frequency response. In

order for conventional plant to provide reserve it must run part loaded.

Thermal units operate less efficiently when part loaded, with an efficiency

loss of between 10% and 20%. Since some of the generators will run part

loaded to provide response, some other units will need to be brought onto the

system to supply energy that was originally allocated to the plant that is now

running at reduced output. This usually means that plant with higher marginal

cost will need to run, and this is another source of cost.

2.20. The cost of provision of primary response is evaluated on the basis of reduced

efficiency of operation of conventional generators. Wind energy that may

need to be curtailed to maintain the feasibility of system operation, is valued

on the basis of the energy cost of conventional plant as this plant would need

to generate more electricity to compensate for the curtailed wind energy.




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2.21. Furthermore, operating an increased number of generators part loaded will

increase fuel cost and CO2 emissions. These were also evaluated.

2.22. Finally, sensitivity studies were carried out to consider the significance of the

inertial effect of wind turbine generators, generator droop settings (influencingrate of change and magnitude of primary response) and the penetration of

wind generation.




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3. Quantification of the value of fault ride through capability

3.1. The evaluation process, based on the developed response model, is composed

of the following steps that are carried out for each half hour of the year:

• Evaluate the net demand (ND) for the considered half hour. Net demand is

defined as the portion of gross demand that is supplied by conventional

generation.

• Evaluate the maximum credible loss (MCL) of generation for the

considered half hour.

• Given the above two parameters (ND and MCL), determine the primary

response (PR) required and if necessary enforce the system feasibility by

curtailing wind generation.

• Evaluate the cost of providing primary response, cost of wind energy

curtailed and resultant CO2 emissions, for the half hour considered.

Net demand

3.2. The used annual gross demand8 and wind output data is shown for all 17520

half hour periods in Figure 3-1 and Figure 3-2 respectively.

Figure 3-1: Gross demand profile Figure 3-2: Wind output profile

3.3. The net demand profile is determined by subtracting the wind generation

output at a particular half hour period from the corresponding gross demand.

8 The dip at period 10,000 represents the lower demand period during the last week of the calendar year.




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Evaluation of maximum credible loss

3.4. The maximum credible loss is modelled as the sum of the maximum expected

loss of conventional generation and a certain amount of wind generation. The

latter is modelled as the product of the actual wind output at the particular half

hour and the wind power loss factor (WPLF). The WPLF defines the

proportion of wind generation that could be lost as a result of a critical fault

on the transmission system. The WPLF will be driven by the location of wind

farms and the degree of fault ride through capability. For example, a WPLF of

10% represents a scenario in which up to 10% of the actual wind generation

output in the particular half hour could be lost due to a fault at a critical

location. A WPLF of 0% represents the situation where wind generation is a

fully compliant with the proposed grid code.

3.5. Two maximum credible loss criteria are used in this study: (i) MCL-high

assumes a 1320MW loss of conventional generation of plus the loss of wind

generation. (ii) MCL-low assumes a 1000MW loss of conventional generation

plus the loss of wind generation. However, MCL-low is considered to be

1320MW if the combined loss of conventional plant and wind generation add

up to a value lower than 1320MW.

3.6. The MCL-high will be relevant if the location of the critical fault is on the

circuit leading to Sizewell B in case a significant amount of wind power could

be lost as a result of such a fault. On the other hand, MCL-low represents a

situation with the location of the critical fault being elsewhere in the system,causing an outage of 1000MW of conventional generation plus a certain

amount of wind generation. This case is potentially relevant given the capacity

of a typical generating station of 2000MW and the circuit arrangements that

could credibly lead to a loss of 1000MW of conventional plant, following a

permanent fault on one of the outgoing circuits.

Response requirement evaluation

3.7. In practice, the flexibility of the generation system tends to vary with loading

conditions. At times of low demand, the system flexibility is generallyreduced, as less flexible plant dominates the generation mix, while during high

loading conditions more flexible plant is usually present. This would tend to

increase the difficulty and cost of maintaining sufficient response on the

system during low loading conditions.

3.8. Using the developed generic response model of the system, we derived the

system response required to meet various levels of generation losses. This was

carried out for two generation systems of different levels of flexibility: (i) high




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flexibility system (PR-high, optimistic scenario) in which all generators could

provide frequency response, and (ii) low flexibility system (PR-low) in which

only half of the total number of generators take part in providing the service.

The resultant response requirement curves for generation losses of 1GW up to

4.5GW were evaluated as a function of net demand. This is shown in Figure

3-3.

Figure 3-3: Primary response requirement curves

3.9. Each curve in Figure 3-3 shows the primary response requirement for a given

loss and varying net demand. For instance, the high flexibility system (PR-

high) can withstand a loss of 3GW for net demands exceeding 15GW.

Feasible system operation cannot be maintained for lower net demands. In the

case of the low flexibility system (PR-low), the net demand must exceed

23GW so that a loss of 3GW could be withstood. The primary response

requirement to withstand a 3GW loss of generation decreases from 3.3GW to

2.4GW for a net demand increase from 15GW to 50GW respectively.

3.10. Three characteristic areas can be identified. Area A (below PR-low line)indicates feasible operation conditions for the low flexibility system. For any

given loading condition (net demand) and for a given instantaneous loss of

generation, the amount of primary response required to contain the frequency

drop caused by the loss can be determined from Figure 3-3. However, there is

a minimum net demand constraint for generation losses exceeding 1.75GW

that is indicated by the PR-line. The intersection points of the PR-low line

with the primary response curves for a given loss indicate the minimum net

demand required to be able to withstand a given loss.

C

A

B




Page 21 of 30

3.11. The intersection points of the primary response curves and the PR-low line

identify system conditions in which the maximum primary response capability

of the low flexibility system equals the primary response requirement. For the

same loss, the system operation is not feasible for lower net demands because

the primary response requirement would be increased but the primary

response capability would be reduced. There are two options to maintain

feasible operation for lower net demand conditions: (i) Reduction in

maximum critical loss. (ii) Increase in primary response capability.

3.12. For any point in area B (between PR-high and PR-low lines) the potential loss

of generation can be accommodated only in the high flexibility system.

However, this would present an infeasible region for the low flexibility

system. For instance, at a net demand level of 20GW, the low flexibility

system can withstand a loss of generation of about 2.75GW, while the high

flexibility system can handle a loss of about 4GW. As expected, the high

flexibility system can handle higher losses of generation than the low

flexibility system9.

3.13. During low net demand conditions, the system has a relatively low primary

response capability and low stored kinetic energy10. Therefore, high losses can

cause a rapid frequency drop, as can be seen from Equation 2-1. System

conditions can arise in which sufficient frequency response cannot be

provided to contain the frequency within the required limits. Such infeasible

operation conditions must be avoided. Hence, a certain amount of windgeneration from fault ride through incapable plant would need to be curtailed

to maintain the feasibility of system operation. Curtailing wind energy will

reduce the magnitude of the maximum instantaneous loss. More wind

generation will need to be curtailed in the PR-low situation than in the PR-

high situation. The reduced wind generation output will need to be

compensated by an equal increase in the output of conventional plant thus

burning more fuel increases operating cost and CO2 emissions. Using the

developed methodology we compute the minimum amount of wind generation

that needs to be curtailed in order to maintain the feasibility of system

operation and then quantify the increase in operating cost and CO2 emissions.

9 The response requirement curves produced by the generic model closely follow these given by NGT(for losses below 1320MW).10 The kinetic energy stored in the power system decreases by decreasing the amount of rotating plant.

Hence, the stored kinetic energy changes with net demand (that equals conventional generation). Themaximum frequency response that can be provided is limited by the amount of conventional generation plant connected, its capability and the operators’ willingness to provide frequency response service.The used frequency response model assumed that wind turbine generators do not provide an inertialeffect or frequency response.




Page 22 of 30

3.14. In area C (left of the PR-high line), even the high flexibility system is not

capable to withstand generation losses exceeding 2GW at all net demand

levels. The intersection points of the PR-high line with the primary response

curves for a given loss indicate the maximum loss that the system can

withstand at given net demand level.

Evaluation of cost and CO2 emissions due to increased response requirements

3.15. The evaluation of cost and CO2 performance of the system is carried out for

various WPLF, losses (MCL-high, MCL-low) and different levels of system

flexibility (PR-high, PR-low).

3.16. As discussed above, generators operating part loaded are less efficient. As a

consequence, the unit cost of electricity production is higher at minimum

stable generation (MSG) compared to full load (FL) operation. A linear

relationship between cost of electricity and loading level is assumed, as shown

in Figure 3-4. The marginal cost of electricity at MSG is assumed to be 20%

more expensive than that at full load. Similarly, the CO2 emissions will

increase. A linear relationship is assumed and shown in Figure 3-4. At MSG

the CO2 emissions are assumed to be 0.72t/MWh and at full load 0.6t/MWh.

Figure 3-4: Marginal cost of electricity and increase in CO2 emissions

Studied scenarios

3.17. Based on the developed dynamic response model shown in Figure 2-2, we

simulated year round operation of the system. A number of case studies were

performed to analyse the cost implications of the potential need to deal with

the increased magnitude of generation losses in the UK system. For each of

the scenarios analysed, WPLFs were varied between 0% and 30%.




Page 23 of 30

3.18. The resultant additional annual primary response cost11 and the total annual

wind energy curtailment are given in Table 3-1 and Table 3-2 respectively.

From Table 3-1, we observe that the additional annual response costs increase

with increasing WPLF. Clearly, the ability of wind generators to withstand

faults is a major driver of the additional response cost.

Scenario: MCL-high MCL-low

WPLF: PR-high PR-low PR-high PR-low Unit

30% 140.5 137.0 106.1 104.6 m£ p.a.

20% 94.4 94.3 63.7 63.7 m£ p.a.

10% 45.7 45.7 24.7 24.7 m£ p.a.

5% 21.4 21.4 14.3 14.3 m£ p.a.

0% 0.0 0.0 0.0 0.0 m£ p.a.

Table 3-1: Additional annual primary response cost

3.19. From Table 3-1, it can be seen that the additional annual primary response costis higher in the MCL-high case than in the MCL-low case. This indicates that

the magnitude of the critical loss is a primary cost driver, as expected. On the

other hand, the importance of the flexibility of the generation system, is less

significant. Clearly, the additional cost does not vary significantly with the

amount of generation that is available (capable) of providing response (PR-

high and PR-low cases).

3.20. The amount of wind generation curtailed in the course of one year is presented

in Table 3-2. The amount of wind generation that needs to be curtailed to

maintain feasibility of system operation is higher for MCL-high cases. In particular, for the PR-low case the curtailment can reach almost 0.9TWh,

which is equivalent to about 3% of the annual wind energy production. No

curtailment is necessary for low WPLFs (more robust wind generation plant).



30% 6 850 879 170 1 715 362 160 MWh p.a.

20% 0 59 225 0 9 480 MWh p.a.

< 10% 0 0 0 0 MWh p.a.

Table 3-2: Wind generation curtailed

3.21. It can be observed from Table 3-1 that in the scenario MCL-high, PR-high,

WPLF of 30%, the value of the additional primary response cost is £140.5m,

while for PR-low, this amounts to £137m per annum12. This difference

11Using our model we estimated the base level annual cost of response to be in order of £65m per year

(for MCL of 1320MW).12 Note also that for lower values of WPLF there is no difference in cost between PR-high and PR-low.




Page 24 of 30

corresponds to operating conditions that fall in the area B (Figure 3-3).

Clearly, in the PR-high case more primary response is available and is used in

conditions of low demand and high wind output. In the PR-low case less

primary response is available and wind needs to be curtailed. Although the

response cost is higher in PR-high case, the amount of wind that would need

to be curtailed would be significantly less, as shown in Table 3-2.

3.22. Conventional generation will substitute for the curtailed wind energy. The

additional energy cost due to wind generation curtailment is costed at

20£/MWh.



30% 0.14 17.6 0.03 7.2 m£ p.a.

20% 0 1.2 0 0.2 m£ p.a.

< 10% 0 0 0 0 m£ p.a.

Table 3-3: Additional energy cost due to wind generation curtailment

3.23. The CO2 emissions due to additional primary response provision and the

substitution of conventional generation for curtailed wind energy is shown in

Table 3-4 and Table 3-5 respectively. For comparison, the annual CO2

emissions associated with operation of a 500MW generator unit is expected to

be in the order of 2.2Mt/annum13.



30% 4.2 4.1 3.1 3.1 mill t

20% 2.8 2.8 1.9 1.9 mill t

10% 1.3 1.3 0.7 0.7 mill t

5% 0.6 0.6 0.4 0.4 mill t

Table 3-4: Additional CO2 emissions due to additional primary response provision



30% 0.0 0.5 0.0 0.2 mill t

<20% 0.0 0.0 0.0 0.0 mill t

Table 3-5: Additional CO2 emissions due to wind energy curtailment

3.24. The total value of the additional system cost (i.e. the annual cost of primary

response provision plus annual cost of wind energy curtailed) and the

13 This would be an average value of annual CO2 emitted by coal and gas fired plant.




Page 25 of 30

corresponding capitalised value (obtained by using conventional net present

value calculation) are presented in Table 3-6 a and b respectively.

3.25. For this purpose we used a discount rate of 7% and duration of 20 years and a

total installed wind power capacity of 10GW. The capitalised values of theadditional primary response cost in £/kW are given in Table 3-6 b. The

capitalised value of the total cost varies from ca 15£/kW (MCL-low,

WPLF5%) up to 163.8£/kW (MCL-high, WPLF30%).



30% 140.6 154.6 106.1 111.8 m£ p.a.

20% 94.4 95.5 63.7 63.9 m£ p.a.

10% 45.7 45.7 24.7 24.7 m£ p.a.

5% 21.4 21.4 14.3 14.3 m£ p.a.

0% 0.0 0.0 0.0 0.0 m£ p.a.

(a) Annual cost



30% 149.0 163.8 112.4 118.5 £/kW

20% 100.0 101.2 67.5 67.7 £/kW

10% 48.4 48.4 26.2 26.2 £/kW

5% 22.7 22.7 15.1 15.1 £/kW

0% 0.0 0.0 0.0 0.0 £/kW

(b) Capitalised cost

Table 3-6: Additional cost of fault ride through capability

3.26. The capitalised additional response costs given in Table 3-6 b correspond to

the value of fault ride through capability. In other words, the additional

investment in improving the fault ride through capability would be

economical provided the cost of equipping wind turbine generators to enable

fault ride through is less than the value given in the table.

3.27. The results of a survey presented in the Grid Code consultation paper [NGC,

SHETL, SPT, 2004] suggest that the cost of equipment associated with

providing fault ride through capability is in the order of 1% up to 3% of thewind turbine cost. This indicates that the cost of providing fault ride through

capability is lower than the associated value quantified in this study,

particularly for high WPLFs. This suggests that it would be cost efficient to

invest in equipment and solutions necessary to enable wind turbine generators

to ride through faults. However, for low WPLF the cost seems to be similar to

the value of fault ride through capability.




Page 26 of 30

4. Sensitivity analysis

4.1. In the context of the value of fault ride through capability investigated in this

study, there are a number of factors that can influence technical and economic

performance of the system with significant penetration of wind power. These

include the amount of wind capacity installed, dynamic frequencycharacteristics of conventional generators and the ability of wind generation to

provide inertial effects.

Total installed wind generation capacity of 15GW

4.2. The MCL-high case has been studied again but assuming a total installed wind

generation capacity of 15GW, i.e. 50% more than in the base case. The

resulting percentage increase in additional primary response cost compared to

the results of the 10GW base case is given for each WPLF in Table 4-1. The

relative increase in cost decreases with increasing WPLF because the primary

response provision is limited and increasing amounts of wind need to be shed.

Scenario: PR-high PR-low

WPLF:

30% 40% 29%

20% 48% 42%

10% 56% 56%

5% 61% 61%

Table 4-1: Percentage increase in additional primary response cost

4.3. The wind energy that would need to be curtailed and the number of half hourly

periods in which the curtailment occurred is presented in Table 4-2.

Considering a WPLF of 30%, the wind energy curtailment would be

equivalent to 5% and 16% of the annual wind generation potential for the PR-

high and PR-low cases respectively. The curtailment would be necessary

during 15% and 31% of the year respectively. Clearly, the amount of wind

that would need to be curtailed for WPLFs above 20% would be unacceptable.

Scenario: Curtailed energy: No. of curtailment periods per year

WPLF: PR-high PR-low Unit PR-high PR-low

30% 2 112 170 7 257 405 MWh p.a. 2 531 5 350

20% 111 100 2 507 800 MWh p.a. 242 2 759

10% 1 825 87 405 MWh p.a. 6 196

5% 0 935 MWh p.a. 0 4

0% 0 0 MWh p.a. 0 0

Table 4-2: Curtailed wind energy and number of half hourly curtailment periods




Page 27 of 30

Governor droop setting 2%

4.4. The previous results considered that all primary response providing generators

have a droop setting of R = 4%. However, from Figure 2-3 it can be seen that

the droop setting has an impact on the primary response characteristic. The

case study corresponding to MCL-high and PR-high was repeated but with agovernor droop of 2%. The 50% lower droop setting resulted in about 27%

lower additional response costs. This indicates that lower droop settings and

the use of plant with faster response characteristics have the potential to

reduce the additional response cost.

Inertial effect of wind generation

4.5. Previous case studies were based on primary response requirement curves

shown in Figure 3-3, which have ignored any inertial effect that DFIG wind

generation could produce. Future developments, for instance the modificationof the DFIG wind turbine control, could enable wind generators to contribute

significantly to system inertia. Given the wide speed range of DFIGs, we

investigated the system benefit with a high inertia constant of 12s assumed for

wind generators. The increased system inertia decreases the gradient of the

frequency change and the primary response requirement. The identified

potential to reduce the additional primary response cost was in the range of

10% up to 30% of the corresponding base case cost. Also, the need to shed

wind decreased. A possible modification of DFIG wind turbine control to

enable inertial effect to be produced is proposed in [Ekanayake et al., 2003].

This work suggests that the cost of implementing this effect would be

negligible.

4.6. It should be noted however, that the proposed Grid Code does not impose any

requirements regarding plant inertia. Furthermore, it is not clear if wind

generators would be incentivised to provide inertial effects and what the level

of compensation would be.

4.7. It is also important to note that the secondary response requirements could not

be influenced by manipulating system inertia.




Page 28 of 30

5. Conclusions

5.1. In this investigation we carried out a number of year round simulations to

estimate the order of magnitude of additional system cost that would need to

be incurred in order to accommodate wind generation of varying degree of the

capability to withstand faults on the UK transmission network.

5.2. The cost associated with accommodating wind generation that is not fully

capable to ride through faults is composed of

(i) Additional response cost, mainly fuel cost due to running the

conventional plant at lower efficiency and

(ii) Additional fuel cost due to the substitution of conventional generation

for wind generation curtailment, that occasionally may be necessary to

maintain the feasibility of system operation

Furthermore, operating an increased number of generators part loaded and

having to curtail some of wind generation will increase CO2 emissions.

5.3. To assess the cost and CO2 performance of the future UK generation system

we developed a simplified generic model of the system primary response

characteristics with 10GW of installed wind generation capacity.

5.4. We estimated the additional cost to vary in the range of £14m to £21m per

annum in the case that the system is required to withstand loss of up to 5% of

wind generation in addition to the loss of conventional plant between

1000MW and 1320MW. For potential loss of up to 30% of wind output (lessrobust wind generation) these additional costs were found to be between

£106m and £155m per annum. Additional CO2 emissions were estimated to

vary between about 0.5Mt and 4.5Mt per annum, depending on the degree of

robustness of wind generators. The amount of wind curtailment for the

potential instantaneous loss of 30% of the total wind output was found to be in

the order of 3% of the total annual wind production, in case of a partially

flexible generation system.

5.5. The results of a survey presented in the Grid Code consultation paper [NGC,

SHETL, SPT, 2004] suggest that the cost of equipment associated with providing fault ride through capability is in the order of 1% up to 3% of the

wind turbine cost. This indicates that the cost of providing fault ride through

capability is likely to be lower than the associated value quantified in this

study, particularly if a large proportion of wind energy (more than 20%) can

be lost due to a fault on the transmission network. In other words the analysis

suggests that it would be cost efficient to invest in the equipment and solutions

necessary to enable wind generators to ride through faults. However, for

reasonably robust wind generation technology (if no more than 5% of wind




Page 29 of 30

could be lost after a critical fault on the network) the additional system cost

seems to be similar to the cost of developing wind turbine generators with a

full fault ride through capability.

5.6. If however more wind generation is to be installed with relatively lowrobustness (if 20% or more of wind output can be lost due to a critical fault on

the transmission network) the overall system cost increase considerably, and

enforcing Grid Code requirements would be clearly economically efficient.

We have quantified these costs for a system with 10GW and 15GW of

installed wind generation capacity.

5.7. Finally, the benefit of wind generation providing significant inertial effects

was estimated. Across the various cases considered, it was found that the

primary response cost could be reduced from 10% to 30% of the

corresponding base case cost. This is clearly significant and this questionshould be investigated further. It should be noted however that the proposed

Grid Code does not impose any requirements regarding plant inertia and that

there is no incentive for its provision.

5.8. Overall, the work carried out clearly demonstrates that, if a significant amount

of wind generation with relatively low robustness is to be installed (with more

than 10% of wind generation output contributing to the maximum credible

loss), this would lead to a very considerable increase in system costs. These

additional costs would be significantly higher than the expected cost of

engineering necessary to provide fault ride through capability. The results of the studies performed suggest that requiring sufficient fault ride through

capability for large wind farms would be economically efficient.

5.9. On the other hand, for connecting wind generation with relatively high

robustness (with less than 5% of wind generation output contributing to the

maximum credible loss) the increase in system cost was found to be in the

same order of magnitude as the expenditure required to enable fault ride

through capability. However, in order to establish the implications of this

more precisely, further studies would be required with actual locations that

may need to be restricted and sizes of wind farms to be considered, including potential consideration of inertial effects. Furthermore, it would be appropriate

to consider the technical and commercial potential for demand side to provide

increased volumes of response services.




Page 30 of 30

6. References

[Anderson, 1990] A low-order system frequency response model, Anderson, P.M.;

Mirheydar, M.; Power Systems, IEEE Transactions on Power Systems, Volume:

5, Issue: 3, Aug. 1990, Pages: 720 - 729

[Ekanayake et al., 2003], Ekanayake, J, Holdsworth, L and Jenkins, N. Control of

DFIG wind turbines. Power Engineer, vol. 17, no.1, 2003, pp. 28 – 32.

[Erinmez, 1999] NGC experience with frequency control in England and Wales-

provision of frequency response by generators, Erinmez, I.A.; Bickers, D.O.; Wood,

G.F.; Hung, W.W.; Power Engineering Society 1999 Winter Meeting, IEEE, Volume:

1, 31 Jan.-4 Feb. 1999, pp: 590 - 596 vol.1

[Johnson, 1998] Technical requirement and despatch of frequency response power

reserve services, Johnson, P.; IEE Colloquium on Economic Provision Of A

Frequency Responsive Power Reserve Service (98/190) , 5 Feb. 1998, Pages:1/1 – 1/4

[Kundur, 1994] Control of Active Power and Frequency Control, Chapter 11, Power

System Stability and Control, Prabha Kundur, McGraw Hill, ISBN 0-07-035958-X

[NGC, 2001] Response Requirements, Response Prices & Curves, The National Grid

company plc, Market Development: March 2001, download: 24.02.2004,

http://www.nationalgrid.com/uk/indinfo/balancing/pdfs/prices.pdf

[NGC, 2004] National Grid, Grid Code Consultation Document H/04, Grid Code

Changes to Incorporate New Generation Technologies and DC Inter-connectors

(Generic Provisions), 23.06.2004

[NGC GC, 2004] National Grid, Grid Code, Issue 2 - Revision 15 - 22nd March 2004,

http://www.nationalgrid.com/uk/indinfo/grid_code/mn_current.html

[NGC, SHETL, SPT, 2004] National Grid Company plc, Scottish Hydro-Electric

Transmission Ltd, Sp Transmission Ltd, Background to proposed changes to England

& Wales and Scottish Grid Codes Connection Conditions to Incorporate Non-

synchronous Generation Technologies, Supporting Paper for: NGC Consultation H/04

and SHETL & SPT consultation SA/2004, 23 June 2004

[Tyndall, 2003] Integrating Renewables and CHP into the UK Electricity System,

Tyndall Centre for Climate Change Research Project TC/IT 1.30, An Investigation of

the Impact of Renewables and CHP on the GB Central Generating System, X. Wu, N.

Jenkins, G. Strbac, The Manchester Centre for electrical Energy, UMIST, 2003

Notes from discussions with Dr. N Tleis and Dr. L Dale from NGT.

Documents

Value of Fault Ride Through capability of Wind generation in UK.pdf