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SpecifLing a Turbogenerator’s Electrical Parameters guided by Standards and Grid Codes

C.-E. Stephan and Z. Baba

Abstract--Turbogenerator technical requirements in private utilities Grid Code documents and established International Standards are discussed together with the impact of turbogenerator electrical parameters on design and cost. The differences in turbogenerator parameters required between Grid Codes and International Standards are also highlighted. These differences are the result of obligations on the privatised electricity companies to ensure a stable and flexible electricity system under challenging electricity market conditions. The authors highlight these challenges and argue for a greater degree of harmonisation between Grid Codes and International Standards which would benefit all parties. The paper refers to the Grid Code in England and Wales where National Grid operates one of the most advanced regulated electricity markets in the world, and reports on current proposals to harmonise the Grid Code requirements for turbogenerators with those of IEC standards.

Index Terms--Ceiling Voltage, Electrical Parameters, Excitation System, Grid Code, Inertia, Reactive Power, SCR, Stability, Standards, Turbogenerator.

I. INTRODUCTION The liberalisation of the electricity market caused great

challenges due to the separation of production, transport and supply of electrical energy. To ensure a safe, secure and economic supply of electricity, formal interface rules were put in place and which were not required before privatisation. As a consequence, private utilities around the world have prepared Grid Code documents which specify plant performance to meet the above obligations. The Grid Code documents will vary depending on the local regulatory, legal and technical environment.

Turbogenerators are major components of the electrical power system and are required to meet the technical requirements of the utilities Grid Codes which in many cases do not align with the established international standards such as IEC and ANSI. In addition, some requirements specified in utilities’ Grid Codes are new and go beyond established National and International Standards.

Z. Baba is with the National Grid Company plc, System Strategy and Design, Kirby Comer Road, Coventry CV4 MY, UK (e-mail: zein. baba@uk.ngrid.com).

C. E. Stephan is with ALSTOM (Switzerland) Ltd., Turbogenerator Business, CH-5242 Birr, Switzerland (e-mail: carlemst.stephan@power. alstom.com).

This paper aims to explain some of the turbogenerator electrical parameters and their. impact on the electrical power system. The impact of the turbogenerator parameters on the design and cost will be explained and the difference in turbogenerator technical requirements between the International Standards and those adopted by NGC will be highlighted. The paper also refers to the latest NGC Grid Code reactive power review which, if approved, may result in harmonisation of the NGC Grid Code electrical parameters with those specified in International Standard IEC 34-3.

11. CHALLENGE OF PRIVATISATION FOR ELECTRICITY MARKET A traditional state owned electricity system is usually

planned and designed by a single body with the authority to decide where new power stations are to be located. However, recent privatisation and liberalisation of electricity markets around the world has meant that new generators are being connected to the electrical power system in relatively short times at locations that cause (together with the closure of older generation) significant changes in the pattern and level of power transfers across the system. To safeguard the electrical power system under liberalised electricity markets, Grid Codes were written in different countries specifiing the technical and operational characteristics of plant owned by the different parties involved in the production, transport and consumption of electric power. This is necessary in order to ensure a certain level of quality of supply which must be delivered to the end-users.

One of the most advanced regulated transmission systems in the world is that of the National Grid Company plc (NGC) which owns and operates the transmission system in England and Wales. NGC has a statutory duty under the UK Electricity Act 1989 to develop and maintain an efficient co-ordinated and economical system of electricity transmission and to facilitate competition in the supply and generation of electricity.

The challenges faced by NGC and other privatised electricity companies include the establishment, operation and maintenance of a dynamic framework of regulation and commercial mechanisms which ensures a secure, stable and efficient electricity system. For the UK system there are legal obligations on various parties involved in the generation, transmission, distribution and supply of electricity. Ancillary service agreements between NGC and the generating parties for frequency response and reactive power have to be formulated and reviewed using a competitive mechanism to

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ensure cost of these services is kept to a minimum. There are connection agreements between NGC and its customers which include the technical specification of the customers’ plant to ensure that there are no adverse effects on NGC or other customers’ equipment.

NGC has an obligation to review the requirement of its Grid Code to ensure the safety, security and efficiency of the electrical system. To fulfil its obligations NGC is currently involved in a major Grid Code review of the technical specification and performance requirements of generators connected to NGC system. This review was initiated following developments in the market for reactive power and parallel comments from machine manufacturers. The Grid Code Review Panel (which represents parties involved in the England and Wales electricity market) established a working group representing NGC and generating companies in late 2000 to review the generator parameter requirements associated with reactive power provisions including the generator short circuit ratio. This review is continuing but this paper mentions some proposals that are currently subject to consultations with interested parties. The potential implication of this review on generator electrical parameters is highlighted in Section IV.

111. GENERATOR PARAMETERS - TECHNICAL CONSIDERATION Turbogenerators are the engine of the electrical power

system. Their prime purpose is to provide real power. However, they are also required to provide reactive power and to have certain technical capabilities to support the electrical power system and maintain stability. In this section the main turbogenerator parameters affecting stability and reactive power capability will be discussed. The impact of these parameters on design and cost will be described. In addition, the capability of the generator to withstand pollution from the power system will be highlighted.

It should be noted that turbogenerator parameter specification has changed over the years. In the past, these were specified with higher design margins. This is mainly because modern turbogenerators employ faster and more sophisticated control systems which enhance the performance of the machine and increase stability limits. Another reason is that nowadays it is possible to built bigger machines with higher efficiencies.

A. Short Circuit Ratio The short circuit ratio of a generator (SCR) is defined as the

inverse of the value of its saturated direct axis reactance. It determines the generator leading reactive capability and has a direct impact on the static stability.

A larger SCR requires more ampere-turns in the field winding for producing the same apparent power of a generator. The output of an electrical machine is limited by the maximum permissible temperature rise. More ampere- turns in the field winding require in most cases a larger rotor volume and therefore an overall larger machine.

Increasing a generator SCR from 0.4 to 0.5 results in an increase in the total machine volume of about 5 to 10% depending on the type of the generator. The impact on generator cost would be in the same range. However, the cost impact can be more dramatic if a change in generator technology is necessary, e.g. if hydrogen cooling instead of air-cooling is required.

In addition the SCR has an impact on the efficiency. With more ampere-turns in the field winding the losses of the field winding will increase. This also depends on the size and design of the generator. Typical reduction in the overall efficiency is in the range of 0.02 to 0.04 per cent for increasing the SCR from 0.4 to 0.5.

B. SCR Impact on Static Stability The impact of the SCR on static stability can be illustrated

by considering the equation for the torque of a synchronous generator:

T = SCR * U,* U *sin 6 (1)

where, Uf = the field (or intemal) voltage of the generator U = the terminal (or armature) voltage of the generator 6 = the load angle SCR= I & X, = saturated direct axis reactance

The generator is assumed to be connected to an infinite bus with constant voltage and of cylindrical (round rotor) type.

From equation (1) it is obvious that if the SCR is larger, larger torque can be achieved. Also, for the same output power the load angle is smaller for a higher SCR. This means that at large turbine power outputs the generator can provide larger torque with ample margin to the stability limit.

On the other hand, for a voltage dip of AU, the increase in the load angle is smaller for a machine with higher SCR. Therefore, under power system voltage dips conditions a generator with higher SCR possesses a higher stability margin.

In practice the power system will have an impedance and the maximum machine torque can be expressed as (ohmic losses neglected and no voltage regulation assumed):

Tm = Uf * U,/(Xd+XJ (2) Where, U, = grid voltage (infinite busbar) X, = total reactance of grid including generator transformer

The above equation also defines the static stability limit at maximum power output.

The impact of SCR and external impedance X, on static stability is illustrated in Fig.1 for different values of X, and for SCR values of 0.4 and 0.5. The generator is assumed to be running at 85% rated MW output and a leading power factor of 0.95. It is clear from Fig.1 that a higher SCR will improve the generator stability limit however the improvement becomes less significant if the generator is connected to a weak grid location.

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3 0.9

0 89

a 088

a 085 5 084

g 082

5 087

2 086 c

5 083 I 0 81

0 8

I I I

I

0 005 0 1 015 0 2 025 0 3 035 External Reactance Xe (P.u.)

Fig 1, Theoretical limit for static stability as a function of the extemal reactance Xe including transformer and gnd Generator operating point Active power 0 85p U , p f 0 95 leading (IEC requirement)

With modem static and rotating excitation systems employing fast voltage regulator and including a load angle limiter, the static stability of a generator no longer has the meaning of 30 or 40 years ago [ 11. The AVR will intervene to keep the armature voltage constant through alteration of the exciter current, thus ensuring that the power angle does not exceed the tolerable limit and therefore securing system stability. In fact, operation beyond the static stability limit is even possible, i.e. in the under-excited mode as shown in [2].

C. SCR and Generator Transient Reactance Impact on Transient Stability

After clearing a fault on the grid the generator has to remain stable within the recovered network. The stability time limit is definitely shorter for a smaller SCR. However, in this case

0

*' m c

Time (s)

Load angle and speed of turbogenerator B for a 3-phases short Fig. 2, circuit at HV terminals of generator (data in Table 1).

D, Inertia Constant The inertia constant of a rotating machine plays an

important role in transient stability. Larger inertia constants give longer critical clearance times to help maintain stability. In the previous example, using the same inertia constant as for machine A would reduce CCT for machine B by about 4%.

The above observation can be deduced from clauses 19 and 26 of IEC 34-3 which require a smaller SCR for an air-cooled generator compared to that of an hydrogen-cooled one. This is because the former has a higher inertia constant than the latter.

additional factors like the generator transient reactance are more important. This is illustrated below with a typical example.

A generator is assumed to be connected to an infinite

generator step-up transformer was simulated- At the Point of fault the voltage drops to zero but once the fault is cleared the voltage recovers to its pre- fault value. Two generators having similar SCRs but different transient reactance values were studied. The data given in Table 1 represents a hydrogen- cooled machine A and an air-cooled machine B. Fig. 2 illustrates the load angle and per unit speed for the machine B

of Table 1, the critical CkaranCe time (CCT) where the generator remains stable is significantly higher for generator B with the lower transient reactance.

E. Reactive Power Capability / Rated Power Factor A generator not only converts turbine mechanical energy to

active electrical power, but also produces or absorbs reactive

well known power chart. For the definition of the power chart the significant are the rated power factor and the SCR. The rated power factor determines the reactive power which can be delivered to the and the SCR defines the reactive power which can be absorbed during under-excited operation until the static stability limit is reached.

For the system what is important is not just the reactive

delivered at the high voltage terminals of the generator transformer. During overexcited operation the consumes reactive power which is not fed to the system and during under-excited operation the transformer helps to absorb reactive power delivered by the system.

I ) Impact on machine design and operation For the same MW rating, the lower the power factor of a

generator, the higher is its MVA rating. The size and therefore the costs of a generator are determined by the MVA power (apparent power). For the same active power, a lower rated power factor requires a bigger machine volume due to the higher ampere-turns needed in the rotor. In addition the generator transformer must be specified for a higher rated power.

busbar. A three-phase short Circuit fault On the HV-side Of the power. The reactive capability of a machine is expressed in the

where stability can just be achieved. As shown in the last row power capability of the generator, but what reactive power is

TABLE 1 MACHINE DATA AND CRITICAL CLEARANCE TIME FOR DIFFERENT

TYPES OF TURBOGENERATORS

* reduced to 420ms if inertia is same as for machine A ** as seen from the generator terminal

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Power Factor 1 0.9 0.85 Add. Losses Min* 0 1.6 2 (kW/MVA) Max** 0 3.5 4.1

Operating at a lower lagging power factor causes higher losses in the generator. Table 2 illustrates the additional losses per MVA for different reactive power requirements given for two typical examples. With the same h4W output, operation at lower power factor require higher stator current and an increase in the field current. Delivering more reactive power will increase the additional losses per MVA.

0.8 0.75 2.2 3.2 4.5 4.6

** corresponds to a hydrogen cooled generator

F. Ceiling Voltage and Excitation System Ensuring a good stability in the grid requires fast control of

the armature voltage and consequently a fast adjustment of the field current. The higher the ceiling voltage the faster the field current can be adjusted to the required value. Nowadays ceiling voltages of 1.6. - 3.0pu (max. ceiling voltage / rated field voltage) are required. However, it must be noted that there is a limit to the improvement in the transient stability with ceiling voltage. A study of the effect of the ceiling voltage on the transient stability of a SOOMVA generator has demonstrated that reducing the ceiling voltage from 2pu to 1.6pu had the effect of reducing the CCT by 4%. However, increasing further the ceiling voltage to 3pu did not improve the CCT at all.

The ceiling voltage has an impact on the rotor design. The field winding insulation of the rotor has to be adapted to the higher voltage levels. This will affect the creepage distances and requires a few millimeters more space for the creepage blocks. The impact on the rotor diameter is not large. However, in larger machines where there are mechanical limits related to the rotor, efficient use of available space is paramount. In addition, the excitation transformer will be of a larger design which has a significant impact on the overall cost of the excitation system.

G. Voltage andffequency variation The size of a generator is influenced by the requirement of

voltage and fiequency variations. The voltage is limited by the maximum permissible flux density in the generator. If the generator is required to operate with a higher level of fiequency and voltage variation then the magnetic path in the generator must be increased by the ratio :

Where, U,,,: maximum voltage U,: rated voltage f.: rated frequency f required minimum frequency

The worst case is a combination of underfrequency and overvoltage operation and this will have a notable impact on the machine size. As the magnetic path represents some 2/3 of

UdJn * (fn-f)/G (3)

the total active part of the machine then a 10% overvoltage requirement instead of 5% would result in about 3% more volume and require a different design of the generator. Also, the requirement for undervoltage operation at rated output requires higher armature winding current thus the requirement for larger copper cross section and hence the generator size must be increased.

It should be noted that in case of employing a tap changer on the generator transformer, the requirement for the voltage variation on the generator side is less important because part of the voltage variation on the generator side is compensated by the tap changer.

H. Negative sequence load and harmonics Voltage unbalance on the grid causes the generator to have

negative phase current which causes additional losses in the rotor. Similarly harmonic pollution from the grid causes additional losses in the rotor. Harmonics generated on the grid can be represented as an equivalent negative phase sequence (nps) current by machine manufacturers and used for design purposes.

In case of higher requirements for the nps currents (or harmonics) a modification of the rotor damper design may be necessary. This would normally require an optimized damper system in the pole zone of the rotor.

Iv. NGC GRID CODE AND INTERNATIONAL STANDARDS REQUIREMENTS

The NGC Grid Code defines plant requirements with respect to frequency and voltage control and overall system stability. Similarly other Grid Code documents around the world specify plant technical requirements to suit their own systems. The technical requirements for turbogenerators in utility Grid Codes will usually differ from those specified in International Standards. This section gives a comparison between the NGC Grid Code requirements and those defined in turbogenerator International Standards.

A. NGC Reactive Review One of the aims of the current NGC reactive power review

is to minimize unnecessary cost to generating companies by aligning the NGC Grid Code requirements with those in International Standards where possible. The proposals are to facilitate the connection of generators designed to International Standards and to enable as much of a generator’s reactive capability range as is practicable to be offered under commercial contracts rather than under a Grid Code obligation. The proposed changes define the reactive performance of generators in two ways: design requirements and operational requirements. For the design requirements, it is proposed that these will align with, and refer to, the international standard IEC 34. The operational requirements will be defined functionally e.g. ability to control the reactive output of generating units across specified system voltage ranges. There will be minimum operational requirements for

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voltage/reactive performance that will apply to all generating units whether contracted in the reactive power market or not. These requirements are set by the inherent characteristics of the generating units and plant and system controls.

B. Short Circuit Ratio The NGC Grid Code currently specifies a minimum short

circuit ratio of 0.5. However, following the above review it is proposed that the SCR requirement would be relaxed to a new minimum value of 0.4 which is broadly in agreement with IEC 34-3 for the generator sizes that are likely to connect to the NGC system.

The SCR requirement in IEC 34-3 depends on generator size and type. For hydrogen cooled or liquid cooled machines, the minimum SCR value is 0.45 for units with rated output not exceeding 200MVA. For units rated between 200MVA - 800MVA and above SOOMVA minimum SCR values of 0.4 and 0.35 are specified respectively.

It should be noted that defining a general rule for a minimum SCR is unlikely to be possible due to the difference in stability margins at various locations of the grid. As shown in Section I11 a power plant connected to a weak point on the grid is likely to require a higher SCR to maintain machine stability. In this case it may be necessary for the grid owner/operator to impose higher technical requirements on the generator via a site-specific contractual connection agreement.

C. Reactive Power Requirements The NGC Grid Code currently states that generators must be

able to operate between a 0.85 lagging power factor and 0.95 leading power factor at rated active power output. However, under the current review it is proposed that the new requirement would be relaxed to a maximum of 0.9 power factor lagging.

In IEC 34-3 the standard rated power factors at the machine terminals are 0.85 and 0.9 lagging for both hydrogen and liquid cooled machines. However, these values are not mandatory.

It should be noted that operation at a leading power factor of 0.95 may not always be possible due to stability issues. In the case of a weak grid this may require a higher SCR than stipulated in the IEC or current NGC Grid Code. Again and as mentioned above it is not possible to define a general rule for machine parameters which can be applied at all locations in an electrical power system.

D. Excitation System and Ceiling Voltage NGC requires that the generator excitation system including

the excitation source and a continuously acting automatic voltage regulator must meet specific requirements for steady state voltage control and transient voltage control. These requirements are site-specific but typically NGC requires that the excitation source should be capable of- (i) providing its upper and lower ceiling voltage to the

generator field in a time not exceeding 50 milliseconds

(ii) attaining a ceiling field voltage on-load of not less than 2 per unit of rated excitation voltage and in the case of static exciters a negative ceiling level of 1 . 6 ~ ~ .

E. Voltage and Frequency Variation Requirements The general NGC requirements are that generator steady

state performance should not be affected by specified changes in system voltage and frequency. The NGC Grid Code requires generating units to:- -

be able to operate continuously within the system frequency range of 47.5 - 52Hz and for a period of at least 20 seconds between frequency range of 47.5 - 47Hz. be capable of continuously maintaining constant active power output for system frequency changes within the 50.5 to 49.5Hz range. However, for system frequency changes within the 49.5 to 47 Hz range any reduction in output power must not be greater than pro-rata with falling frequency, with the reduction in power output being no more than 5% for a system frequency drop to 47Hz. be able to maintain their active power output under steady state conditions for system voltage changes of +5% at 400kV and +lo% at 275kV and 132kV be able to make their reactive power fully available within voltage changes of f5% at 400kV, 275kV and 132kV.

The IEC requirement is for fS% voltage variation and e% frequency variation. An overvoltage of 5% is only allowed at rated or higher frequency. Operating at lower frequency requires a linear reduction of the admissible overvoltage because of overfluxing of the generator.

It should be noted that the NGC requirements for voltage variation can be met by the IEC Standard due to the use of tap changers on the generator transformer.

F. Negative Phase Sequence Voltage The requirements for the NGC system are that the negative

phase sequence (nps) voltage component should remain below 1%. However, short duration peaks up to 2% are permitted with the prior agreement of NGC and following a specific assessment of the impact of these nps levels on NGC and other customers’ equipment. The generators are required to withstand the above levels of unbalance in the voltage waveform. In addition, the generators are required to withstand without tripping the nps loading incurred by clearance of a close-up phase to phase fault, by system back up protection on the NGC transmission system.

IEC 34-1 specifies machine nps current capability as 8% for machines with output less than 350MVA and reduces this value linearly to 5% for outputs up to 1260MVA.

The voltage unbalance specified by the grid operator is used to determine the nps current. Assuming a generator negative sequence impedance of 0.lpu (this is about the minimum subtransient reactance allowed in IEC) and a generator transformer impedance of 0 . 1 5 ~ ~ (on rating) then 1% voltage unbalance results in a negative sequence current of:

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i2 =V2/(X2+XT)=0.0 l/(O. 1 +O. 15) = 0.04 PU = 4%

G. Harmonic Distortion Levels The levels of the total harmonic voltage distortion (THD)

specified in the NGC Grid Code are being revised to take into account the greater harmonic emissions from modern power electronics based load. Currently, Grid Code harmonic voltage THD limits are 1.5% and 2.0% at NGC 400kV and 275kV systems respectively. However, the revised NGC Grid Code will refer to the use of Engineering Recommendation G5/4 for harmonic voltage distortion planning and compatibility levels. It is proposed to increase the THD planning levels to 3.0% for the connection of non-linear load and the THD compatibility levels to 3.5%. These levels are specified using Intemational Standards nomenclature.

The THD level can be converted to an equivalent nps current. Assuming a worst case scenario where the 5‘h harmonic voltage is 3% and generator data as in section F above. The corresponding 5“ harmonic current will be:

is= 0.03/(5*(0.1+0.15)) = 0 . 0 2 4 ~ ~

The equivalent nps current [3] would be 0 . 0 2 6 ~ ~ .

V.CONCLUSIONS AND FUTURE TRENDS Turbogenerators are a major part of the electricity system

and are specified differently in Grid Code documents around the world. The turbogenerators and other plant are specified in such a way as to enable the grid operator to provide a secure and stable electrical system to meet its obligations. However, in many cases the existing International Standards specify different turbogenerator technical values to those in Grid Codes. Since the Intemational standards are the base for the generator manufacturer for specifying his products this difference in generator technical specification is not helpful and has in many cases high cost implications. If there is a genuine need for more stringent requirements then the turbogenerator manufacturers should adapt to these higher reauirements and the International Standards should be

weak grid connection points higher technical requirements may not be avoidable.

VI. ACKNOWLEDGEMENT The authors gratefully acknowledge the help and contribution of D J Gray and D J Coates particularly in matters related to NGC Grid Code reactive review.

VII. REFERENCES

[ I ] A. Murdoch, H. C. Sanderson, R. A. Lawson, “Excitation Systems - Performance Specification to Meet Interconnection Requirements”, IEEE PES WM 2000, Singapore. D. Oeding, P. Nemetz, “Stability and voltage regulation of large turbo- alternators in power systems; effect of machine data and excitation system“, IEEE Winter Power Meeting 1970, Paper 70 CP 199-PWR G. Neidhbfer, A. Troedson, “Large Converter-Fed Motors for High Speeds and Adjustable Speed Operation: Design Features and Experience”, IEEE Transactions on Energy conversion, Vol. 14, No.3, September 1999.

[2]

[3]

VIII. BIOGRAPHIES

Zein Baba was born in El-Mina, Lebanon, in 1959. He holds a B.Sc. in electrical engineering from the Middle East Technical University, Turkey and an MSc. and a Ph.D. from the University of Manchester Institute of Science and Technology (UMIST), UK.

His employment experience includes Balfour Beatty Engineering & Projects Ltd., Engineering Power Development Consultants and The National Grid Company plc in the UK He specializes in the transmission and distnbution of electrical power He

has particular interest in power quality issues and currently deals with the assessment and testing of turbogenerators technical performance in England and Wales. He is a Member of the Institution of Electrical Engineers (IEE).

Carl-Ernst Stephan was born in Germany in 1960. He received the Dip1.-Ing. degree in electrical power engineering in 1983 and the Dr.-Ing. degree in 1991 from the University of Kaiserslautern.

He is in his current position head of Electrical Engineering and Design in the turbogenerator business unit of ALSTOM, Switzerland. He started his professional career in 1990 in the development of

rewritten accordingly. f i e privatised electricity companies their requirements and take a proactive

role in aligning their requirement with those in the International Standards where possible. This will obviously bring cost benefits to the electricity industry stakeholders.

Intemational Standards do not exist in isolation and must reflect requirements placed on the plant in service. We might expect over time for Grid Codes of typical utilities and plant standards to converge but this is not a one way process. It is wished that the trend demonstrated by NGC reactive review will continue and a harmonisation between Grid Codes and International Standards will be achieved where possible. The ideal position would be for the majority of generating plant in most electrical systems to have technical requirements compatible with existing (or if required to enhanced) International Standards. However, it should be expected that at

turbogenerators studying special problems in the design of large turbogenerators. In particular he was responsible for the electromagnetic design and cooling of air-cooled turbogenerators with highest unit ratings.

also

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