continuity of electricity supply

8/9/2019 Continuity of Electricity Supply

1/6

Abstract: It is expected that Dispersed Generation (DG) will

play an increasing role in electric power systems in the near fu-

ture. Among the benefits that DG can give to the power system

operators and to the electricity customers, one of the most attrac-

tive is the possibility of improving the continuity of power supply.

DG plants can be designed to supply portions of the distribution

grid in the event of an upstream supply outage. Techniques for

controlling DG plants that use feedback of only locally measur-

able variables are presented. This solution allows correct system

operation and switching between parallel and isolated modes

without needing online communication of control signals between

the generators.

The control technique is described with particular reference to

inverter-interfaced systems (micro-turbines, fuel cells). Simula-

tions of sample cases including different size and type of genera-

tors are presented.

Index TermsDispersed storage and generation, Inverters,

Power distribution, Power system reliability.

I. INTRODUCTION

HREE major factors are now pushing forward the devel-

opment of distributed resources for electric power genera-

tion.

The first one is the possibility of making exploitable severalkinds of sources such as renewable and co-generation sources

(combined heat and power: CHP), thus improving primary

energy exploitation.

The second factor is associated with the increased difficul-

ties met in developing new transmission and distribution facili-

ties and to the current high levels of power flows in some criti-

cal grid sections.

The last factor regards the high levels of power quality

needed by an increasing number of activities. Such levels can-

not be ensured by the standard distribution systems.

Therefore we can imagine a mid-term scenario in which

many distributed power sources are present that require the

solution of many technical problems. In fact, present-day dis-tribution grids are conceived as a top-down means of con-

veying energy, while the presence of small power plants in

such a grid can sometimes reverse this flow. An extreme case

is that of small isolated systems where the dispersed generators

are (permanently or for short periods) the only active sources

in the network. This big change requires a new approach to

system operation, protection and planning [1, 2].

S. Barsali, M. Ceraolo, P. Pelacchi and D. Poli are with Dipartimento di

Sistemi Elettrici e Automazione, University of Pisa, via Diotisalvi, 2 I-56126

Pisa Italy (e-mail: [email protected]).

II. THE NEW SCENARIO OF DISTRIBUTED RESOURCES

On the technology side, several main options are available

for building dispersed generation sources; some of them are

already well developed (based on Internal Combustion En-

gines (ICE), hydro and wind turbines), others are currently

coming onto the market (based on small gas turbines), others

are expected to be introduced within a few years (based on fuel

cells).

Many DG plants (ICE, small hydro plants etc.) presently use

rotating machinery directly connected to the grid to supplyelectric power.

The new technologies (such as micro turbines, fuel cells,

photovoltaic systems and several kinds of wind generators), on

the other hand, are not suitable for supplying the grid directly.

They are therefore interfaced through an inverter stage. It is

worth noticing that the share of these plants is expected to in-

crease in the future.

From the point of view of the electric power system, DG

sources can offer a wide range of possible services [3, 4]. The

actual exploitation of these possibilities depends on the kind of

plant, on the exploited source, on the choice of the control

system logic and on possible constraints given, for example,

by the thermal load demand in the case of CHP plants.One important way of increasing power supply reliability

could be to supply the most important loads on a protected

network that can be fed by a generator in the event of failure of

the main supply.

An interesting opportunity can derive from the increasing

diffusion of DG resources. Due to the large number of dis-

persed generators we can expect to be installed, we can argue

that in several portions of the distribution grid the DG installed

capacity will reach high values if compared to the local load

demand. These plants could be used to ensure the power sup-

ply of portions of the distribution grid where they are installed.

Automatic Sectionalising Switching Devices (ASSD) can be

sited in the distribution networks to cut areas where the in-stalled dispersed generators can supply the local load [5, 6].

According to this scheme, DG can be used to feed custom-

ers in the event of an outage in the feeding line or in the pri-

mary substation or during scheduled interruptions. Obviously,

voltage and frequency in the islanded portion of the network

have to be controlled.

The main challenge that has to be faced to exploit this in-

triguing possibility is the co-ordination of the numerous gen-

erators for sharing the real and reactive power output and to

control the system frequency and voltage.

Indeed, small generators are often designed to run in paral-

Control techniques of Dispersed Generators to

improve the continuity of electricity supplyStefano Barsali, Massimo Ceraolo, Paolo Pelacchi,Member, IEEE, Davide Poli

T

789

0-7803-7322-7/02/ 17.00 2002 IEEE


2/6

lel to the main grid or as stand-alone devices [7]. At most we

can find a few generators running in parallel on a single plant

and driven by a single control system. Often, the paralleling

and islanding operations of the plant require the system to shut

down and restart in a different configuration.

A flexible solution requires that each generator operates

only on the basis of local measures independently of the actual

configuration of the grid and of the other generators [8].

This is similar to what happens in large power plants wherethe frequency droop control allows the plant to run either on

an island or in parallel to other plants or in parallel to the in-

terconnected power system.

The control system proposed is then based on this principle.

III. CONTROL OF DG SOURCES INTERFACED

WITH ROTATING MACHINES

Rotating machines in dispersed generation systems are usu-

ally associated with reciprocating engines (Diesel or gas en-

gines). If such plants are not used as back-up sources, they are

often associated with heat generation. In this case, the real

possibility of modifying the power output depends on the

thermal load characteristics and on the overall heat generationsystem. In any case, three control possibilities are likely to be

met:

fixed power control,

fixed speed control,

droop control.

The fixed power control logic is adopted for plants running

in parallel to the grid and with no obligation regarding regula-

tion. The electricity generated can be fixed by the needs of the

thermal load associated, or by means of economic evaluations.

In this last case such plants usually run at their maximum

power for most of the operating time.

To supply a local load, for example in the case of back-up

units, an isochronous control is often used. This allows the

adaptation of the power output to the load demand while keep-

ing a constant frequency value. As is well known, no more

than one single isochronously controlled unit can be connected

to a grid.

If more than one unit is to supply a grid, a droop control is

to be adopted. The turning out frequency depends on the load

value according to the droop characteristic. The power sharing

among the units is now possible on the basis of the droop fre-

quency control principles.

IV. CONTROL OF DG SOURCES INTERFACED WITH INVERTERS

A. Description of devices and standard control systems

For the purposes of this study reference will be made to a

generation system (e.g. micro-turbine or fuel cells) having a

DC stage before the inverter. Moreover it will be assumed that,

if the power demand is within the capability of the device, the

DC voltage is kept constant by the primary generator controls

[9]. Therefore the analysis can be limited to the inverter con-

trol itself.

The control scheme of an inverter device can be represented

as shown in Fig. 1

Two cascaded control loops can be identified: the inner one,

the PWM control, concerns the bridge valve pulsing, the outer

one regards the generation of the input signals of the PWM

control based on the chosen control logic, on field measures

and control signals.

Pulses

Powerbridge

Powerterminals

F

ieldmeasures&

c

ontrolsignals

Phasecontrol

PWMcontrol

Amplitudecontrol

Fundamental phase

Fundamental amplitudeFig. 1. Control scheme of an inverter device.

In several cases the phase and amplitude control loops are

integrated in a single control system having two outputs.

Limiting the analysis to the fundamental frequency supplied

by the inverter, the device can be simply modelled as shown in

Fig. 2. In the diagram on the right of the figure, E represents

the fundamental amplitude generated by the inverter (before

the filters), Zfis the equivalent impedance of the filter and, if

applicable, of the transformer installed within the generating

unit, Vis the terminal voltage (after the filters).

E

Z

VfFilter

DC-sideequivalent

+

Transformer

T

Fig. 2. Inverter interfaced generator: principle scheme and equivalent net-

work at the fundamental frequency.

The PWM control effect can be neglected at this stage,

since it has a faster dynamic behaviour with respect to the ex-

ternal loops and does not affect the possibility of exploiting the

system capacity.

Usually two kinds of control can be adopted to operate an

inverter device, namely:

A so-called PQ control: the inverter is operated to meet a

given real and reactive power set point. Therefore the E

waveform must be synchronized with the grid voltage Vand

controlled in amplitude and phase.

A voltage control logic: the inverter is controlled to supply

the load with given values of voltage and frequency. De-

pending on the load demand at such voltage and frequency,

the inverter real and reactive output will be defined auto-

matically.

The first can be adopted when the inverter has to exchange

real and reactive power with the grid, e.g. in power compensa-

tion systems or generation systems that have to supply the grid

itself (grid parallel operation) [10].

The second is suitable for supplying a local load, e.g. in mo-tor drives or isolated systems where the inverter is the sole

power source.

Obviously any attempt to use the PQ control on an isolated

grid would fail due to the absence of a voltage reference and to

the practical impossibility of balancing the load demand ex-

actly. On the other hand, a fixed frequency source (e.g. an in-

verter following the voltage control) could not be paralleled

with the grid.

Therefore the switching between the parallel and the iso-

lated operation requires a control switching between the two

790


3/6

techniques and a synchronization of the inverter to the network

frequency.

A similar but more complex problem is met when several

inverters are connected in parallel with each other and with the

grid, especially if the inverters are spread on a portion of the

grid, instead of being gathered in a single plant. In this case a

central control system should continuously communicate with

all the machines and with the grid interface switch and should

force one of the inverters to become the voltage reference forthe others in the islanded operation.

B. Proposed control logic

The considerable complexity, the high cost and the high re-

liability of the supervision system needed to allow the so-

called automatic islanding of a portion of the distribution grid

supplied by several DG sources could make this possibility an

unattractive option.

On the other hand, a control philosophy based on local

loops would be preferable, each driving a single inverter with-

out the need for intercommunication with the others and keep-

ing the same structure both when running in parallel with the

mains and when supplying an isolated load.

Based on the usual droop frequency control of synchronous

generators, a control system linking the inverter fundamental

frequency to its power output has been developed.

Therefore the inverter is controlled as a voltage source with

frequency and amplitude defined by local control loops (see

Fig. 3).

The modulating signal for the PWM control is:

vm=msin[(t)] (1)

The values of the scaling factor mand of the (t) time func-

tion are determined according to the rules described below.

TotheinverterPWMcontrol

C Maximum power

control (e.g. PI cont.)

C Standard control

(e.g. PI control)

C Maximum current

control (e.g. PI cont.)

P

f2f

C2

PMAX

P

C3m

VREF

V

C4m

IMAX

I

signQ

m

Measuresfromtheinverterterminals

2

3

4

Frequency control

Amplitude control

f

f

f

0

Real power

Frequency

1

1P

Maximumpowercontrol2

Standard droop

control

V I signQ

Switch

logic

P f

Switch

logic

f0

P real power at inverterterminals

Q reactive power atinverter terminals

V voltage at thecontrolled bus

f frequency of themodulating wave

f frequency at no load0

P Maximum real power(prime source limit)

MAX

, m see text. Equation (1)

V voltage set point at the controlled bus

REF

I inverter current

I maximum invertercurrent

MAX

s

Fig. 3. Principle block diagram of the inverter control and power frequency

characteristic

1) Frequency control

As shown in Fig. 3, the steady state link between power and

frequency is defined by the droop characteristic (D=(f0-f2)/f0).

When running in parallel with the rest of the system, the

grid itself fixes the frequency. Therefore if the inverter fre-

quency is higher than the grid frequency, its fundamental phase

shift E-V with respect to the terminal voltage increases to-

gether with the power output as they are linked by (2).

P=VE/Xsin(E-V) (2)

As a consequence, the fundamental frequency will be re-

duced according to the droop characteristic and the inverter

will synchronize to the grid.On a stand-alone system, the frequency will be defined by

the load; i.e. to power P1corresponds the frequency f1in Fig.

3.

If several inverters are connected in parallel to supply an

isolated grid, they will share the load power based on their

droop characteristics in the same way as large power plants

subject to primary frequency regulation do.

More in detail, the frequency control has the measured real

power generation Pas input and the frequency fof the funda-

mental voltage as output (or, rather, its time integral used for

generating the modulating signal of the PWM control, accord-

ing to (1)).

When reaching the maximum allowable output (that is themaximum power the prime source can supply), the control

automatically switches to a fixed power control acting on the

phase shift between the fundamental voltage generated by the

inverter and the voltage measured on the grid side of the fil-

ters. The system returns to normal control when the frequency

exceeds the valuef2by a given margin.

2) Amplitude control

The amplitude control system acts on the mfactor based on

the voltage error V-VREF measured at the inverter terminals

(point T in Fig. 2; other buses can be utilised for the purpose,

however). The choice of the voltage set points of the different

DG plants must be co-ordinated to avoid undesirable reactive

power flows.When the inverter currentIreaches its maximum valueIMAX,

the control switches to a current control. The purpose of this is

to maintain a constant current value. Depending on the sign of

the reactive power flow Q, the system returns to the standard

control when the voltage set point VREFis exceeded by a given

margin.

3) Choice of set points

Usually a DG plant planned to run in parallel to the grid

should be controlled at a given power output. With the control

logic described above, the frequency value f0 (frequency at

P=0) together with the characteristic slope D, univocally de-

fines the operation of the plant. Therefore, since grid fre-

quency fluctuations are very small for almost the whole lengthof operating time, the choice off0fixes the plant power output

and can be used to dispatch the generation.

Similarly the choice of the voltage set points defines the re-

active power flows.

Correct management of the distribution grid with dispersed

generators will therefore require a periodical refreshing of the

various set points, based on contractual agreements between

the operators and on regulation obligations. This can be done

locally, based on the demand of the load and of the generation

process, or by a central dispatching system. Anyway there is

no need for an on-line centralized control system and of a con-

791


4/6

tinuous communication between the various machines.

4) Switching from parallel to islanded operation

The switching transient from parallel to islanded operation

can occur without any modification in the inverter control

logic. In fact when the grid trips the inverter will find a new

operating point defined by the overall characteristic of the sys-

tem (as in the primary frequency regulation in conventional

power systems).

If the connected load is too large to be supplied by the DGsources, the maximum power control forces the inverter fun-

damental voltage to slide with respect to the reference, thus

resulting in an under-frequency that can be used as a signal for

shedding the less important loads.

On the other hand, if the inverters reach the maximum cur-

rent value, due to a high reactive power output, the maximum

current control forces a reduction of the fundamental ampli-

tude and of the reactive power flow. If the total capability is

too low, the system voltage will decrease. This signal also can

be adopted to set a load shedding procedure.

5) Paralleling with the grid

To close the parallel between the survived local grid and the

restored mains, only a paralleling switch located at the point ofinterconnection is needed. Due to the absence of inertia in the

inverter systems they will rapidly synchronize the local grid by

automatically adapting the inverter frequency to the grid fre-

quency by means of the droop power frequency control.

V. SIMULATIONS OF SYSTEM OPERATION

The above-described control technique was tested by means

of simulations in several operating conditions. The configura-

tions considered are:

the paralleling and isolating transients of a single inverter,

the paralleling of two inverter fed stand alone systems,

the behaviour of a portion of a LV distribution grid with

inverter devices and rotating machinery.

A. Single inverter operation

The first operating condition tested regards a single inverter

feeding a local load connected in parallel to the main grid as

shown in Fig. 4.

M

Eq. motor

Inverter

Grid equivalentParallelswitch

Eq. Z loads

Shedding relay

1

2

Fig. 4. Test grid for a single inverter operation

The power amount supplied by the inverter is fixed by the

choice of f0and of the droop value D, given a grid frequency

of 50 Hz.

The sudden loss of the main supply was simulated by the

opening of the parallel switch at t=0.5 s. In this case the maxi-

mum real power the generator can supply is not enough to feed

the local load (Fig. 5). The maximum power control logic acts

trying to limit the power supplied by the inverter by shifting

the fundamental voltage phase with respect to a 50 Hz wave.

This action causes a frequency decay and the intervention of

the shedding relay at t=1 s (Fig. 6). After that, the load amount

is within the generator capability and the control returns to the

standard configuration supplying the load at a frequency value

that depends on the droop characteristic.

time (s)

Power (p.u.)

Active power

Reactive power

0 1 2 3 4 5 6-0.5

0.0

0.5

1.0

1.5

Grid trip

Load shedding

Paralleling

Fig. 5. Real and reactive power supplied by the DG unit

time (s)

Frequency (Hz)

0 1 2 3 4 5 6

47.5

48.5

49.5

50.5

Fig. 6. Frequency on the local grid

After the parallel command has been given at t=2 s the par-

allel switch closes as soon as the paralleling conditions occur

(t=3.6 s). The resynchronization between the inverter and the

grid is rapid and does not cause heavy current transient in the

switch (Fig. 7).

time (s)

Voltage (V)

Parallel switch voltage

Parallel switch current (rms)

Current (A)

0 1 2 3 4 5 6

-1000

0

1000

0

100

200

Fig. 7. Voltage (instantaneous) and current (rms) on the parallel switch

B. Two inverter operation

The ability of the inverter-fed areas to run stably in parallel

with each other without communication was checked on the

sample network shown in Fig. 8.

Inverter 1

Eq. motor 1Eq. Z load 1

Inverter 2

M M

Eq. Z load 2 Eq. motor 2

Parallelswitch

Grid 1 Grid 2

Fig. 8. Test grid for the parallel operation of two inverter fed areas

Initially the parallel switch is open; each inverter feeds the

local load at a frequency value (50.33 Hz on grid 1 and

49.83 Hz on grid 2) depending on the choice of f0, Dand on

the value of the local load L (f0=1.02 p.u. for inverter 1 and

1.01 p.u. for inverter 2; D=0.02 p.u. for both, L1=L2=55 kW).

792


5/6

After the paralleling command has been given, the parallel

conditions occur at t=1.5 s and the parallel switch closes. The

inverters rapidly synchronize themselves solely on the basis of

local real power measures. The new power sharing (Fig. 10)

still depends on the control parameters as well as the final fre-

quency value (50.07 Hz, Fig. 9).

time (s)

Frequency (Hz)

Frequency 1

Frequency 2

0.0 1.0 2.0 3.0 4.049.5

49.7

49.9

50.1

50.3

50.5

Fig. 9. Frequency on grid 1 and 2

time (s)

Active power (p.u.)

Inverter 1

Inverter 2

0.2

0.4

0.6

0.8

1.0

0.0 1.0 2.0 3.0 4.00.2

0.4

0.6

0.8

1.0

Inverter 1

Inverter 2

Reactive power (p.u.)

a)

b)

Fig. 10. Real a) and reactive b) power supplied by the DG units

In the case of a higher load value, the unit having the high-

estf0can reach the maximum power when making the parallel

(see Fig. 11). Therefore it will run at its maximum power while

the second unit will supply the rest of the load as shown quali-tatively in Fig. 12.

time (s)

Active power (p.u.)

Inverter 1

Inverter 2

0.0 1.0 2.0 3.0 4.00.4

0.6

0.8

1.0

1.2

Maximum power

Fig. 11. Real power supplied by the DG units in case of reached power limit

for unit 1

L=P P

f

f

0

frequency

1 1

1

f

f

0

active power

frequency

1P

2

2L=P

2 2

f=f 1 2

active power

P P1 2

P P1 2generation before

paralleling

generation after

paralleling

Fig. 12. Power sharing between two units in case of reached power limit for

unit 1.

C. A sample LV network

The last sample configuration considered is constituted by a

simple low voltage grid fed by a 630 kVA transformer, by

three inverter-interfaced dispersed generators (G1 to G3, e.g.

micro turbines) and by a synchronous generator (G4, e.g. a

Diesel unit). A diagram of this scheme is shown in Fig. 13.

The synchronous generator has a fixed power control; i.e. the

mechanical power is kept at a fixed value (180kW). The three

inverters are controlled as described in section IV. A singledroop value (D=0.02) and three different values of f0 (1.02,

1.012 and 1.01 respectively for G1, G2 and G3) are used.

As soon as the main supply fails (t=1.5s), the three inverters

reach the maximum real power output (first G1 and then G2

and G3; Fig. 16). As a consequence of the attempt to keep the

output within the limit, the frequency starts to decay (Fig. 14).

After the tripping of the load shedding relays, the frequency is

recovered and the system stabilises at a frequency defined by

the load and by the power frequency characteristics.

The new paralleling command is given at t=5 s and the par-

alleling conditions occur at t=7.2 s. The closure of the switch

resynchronizes the generators to the grid. It is worth noting

that the synchronous generator participates in the transientwith its inertia, while keeping the steady state power output

unchanged.

Eq. motor 162.5kVA

running at50kW

G1: i nverter170 kW

250 kVA

M M

G2: inverter100 kW

150 kVA

G3: inverter170 kW

250 kVA

G4: synchr.180 kW

200 kVA

Eq. motor 2125kVA

running at100kW

100 kW50 kvar

50 kW50 kvar

sheddable

100 kW50 kvar

100 kW50 kvar

sheddable

150 kW50 kvar

50 kW50 kvar

sheddable

Main grid

630 kVAz =6%sc

Fig. 13. Scheme of the LV grid adopted for the simulation

time (s)

Frequency (Hz)

0 2 4 6 8 1048.0

48.5

49.0

49.5

50.0

50.5

Fig. 14. Frequency on the local grid

0 2 4 6 8 100.8

0.9

1.0

1.1

1.2

time (s)

Voltage (p.u.)

Fig. 15. Voltage at G1 terminals

793


6/6

-0.5

0.0

0.5

1.0

1.5

-0.5

0.0

0.5

1.0

1.5

-0.5

0.0

0.5

1.0

1.5

0 2 4 6 8 10-0.5

0.0

0.5

1.0

1.5

Power (p.u.)

time (s)

Inverter 1

Inverter 2

Synchronous generator

Islanding

Active power

Reactive power

Active power

Reactive power

Active power

Reactive power

Active power

Reactive power

Load sheddingNew paralleling

Inverter 3

Fig. 16. Real and reactive power supplied by the four DG units (three inverter

interfaced unit and one synchronous generator)

VI. CONCLUSIONS

The proposed control logic for inverter interfaced dispersed

generators proves to be effective in easing the islanding and

paralleling procedures of portions of the distribution grid with

embedded generation. The ability to operate without any

online signal communication between the machines for syn-chronization makes the system cost-effective. An offline local

control system makes it possible to optimise power-sharing

between the units and the reactive power flows.

This can be effectively exploited in the event of main supply

failures to feed, at least partially, the load, thus enhancing sup-

ply continuity.

The technical principle that has been illustrated must be co-

ordinated with the distribution grid operation as well as with

the standards of substations and power switches management.

In particular, the generator operators have to co-ordinate with

the distribution grid operator regarding the control of the par-

allel switches and the real and reactive power exchange.

VII. REFERENCES

[1] N. Hadjsaid, J.F. Canard, F. Dumas, Dispersed generation impact on

distribution networks, IEEE Computer Applications in Power, vol 12,

n 2, April 1999

[2] R. C. Dugan, T. F. McDermott, G. J. Ball, Planning for Distributed

Generation,IEEE Industry Application Magazine, March-April 2001.

[3] T. Moore, Emerging Markets for Distributed Resources, EPRI

JOURNAL March-April 1998

[4] S. Barsali, M. Ceraolo, R. Giglioli, P. Pelacchi, Microturbines for

dispersed generation in Proceedings of CIRED 1999, Nice (France),

June 1-4, 1999

[5] G. Celli, F. Pilo, Optimal sectionalizing switches allocation in

distribution networks,IEEE Transactions on Power Delivery , vol 14 n

3 July 1999

[6] S. Barsali, G. Celli, M. Ceraolo, R. Giglioli, P. Pelacchi, F. Pilo,

Operating and planning issues of distribution grids containing diffuse

generation in Proceedings of CIRED 2001, Amsterdam (The

Netherlands), June 18-21, 2001

[7] M. Etezadi-Amoli, K. Chroma, Electrical Performance Characteristics of

a New Micro-Turbine Generator in Proceedings of IEEE-PES Winter

Meeting 2001, Columbus, OH (USA) January 28-February 1, 2001

[8] B. Lasseter, Role of Distributed Generation in Reinforcing the CriticalElectric Power Infrastructure in Proceedings of IEEE-PES Winter

Meeting 2001, Columbus, OH (USA) January 28-February 1, 2001

[9] S. Banetta, M. Ippolito, D. Poli, A. Possenti, A model of cogeneration

plant based on small-size gas turbine in Proceedings of CIRED 2001,

Amsterdam (The Netherlands), June 18-21, 2001

[10] M. Ceraolo: Modelling Static Watt-Var Compensators using ATP, 3rd

International Conference on Power Systems Transients (IPST99),

Budapest (Hungary), June 20-24 1999

VIII. BIOGRAPHIES

Stefano Barsali(1969): was awarded master and Ph.D. degrees in electrical

engineering by the University of Pisa, Italy, in 1994 and 1998 respectively.

Since 2000 he has been Assistant Professor of Electric Power Systems at theElectrical Systems and Automation Department at Pisa University.

His major research interests regard dynamic simulation of power systems,

distributed generation, electricity market deregulation and electrical and hy-

brid vehicles.

Massimo Ceraolo (1960): was awarded a degree in Electrical engineering at

the University of Pisa in 1985. From 1992 to 2000 he was a researcher, then

an Associate professor of the University of Pisa.

His major fields of interest are: Active and Reactive compensation of

Power Systems, Long-distance Transmission systems, Computer Simulations

in Power Systems, Storage Batteries, electric and hybrid vehicles

Paolo Pelacchi(1951): was awarded his electrical engineering degree by Pisa

University, Italy, in 1976. In 1979 he joined the Electrical Research Center of

ENEL.

Since 1983 he has worked in the Department of Electrical Systems andAutomation at Pisa University first as a researcher, then, from 1992, as an

associate professor and lastly, since 2000, he has been full professor of elec-

tric power systems.

His recent research interests regard electricity market liberalisation proc-

esses with particular attention to the Italian situation.

Davide Poli (1972): received his electrical engineering degree from Pisa

University, Italy, in 1997. He is now a Ph.D. student at the Electrical Systems

and Automation Department at Pisa University.

His research interests regard generation, transmission and distribution

problems related to market liberalisation processes.

794

continuity of electricity supply

Documents