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Grid Code Impact on Electrical Machine Design
K. Mayor, Senior Member, IEEE, L. Montgomery, Fellow, IEEE,
K. Hattori, Member, IEEE, and J. Yagielski, Member, IEEE.
Abstract-- Due to the integration of more renewable energy
sources into transmission grids throughout the world, grid codes
are being adapted to take into account the diversity and
intermittent production of these types of power sources.
These adaptations to the grid code affect new and existing
plant connected to the grid and are putting new demands on the
turbogenerators in many aspects of their electrical parameters
and performance.
The existing machine design codes (e.g. IEEE C50.13 and
IEC60034) do not take into account these new operating demands
and are in need of review. Additionally grid code legislators,
system operators and plant owners need to be aware of the
potential impact on new and existing plant when deciding on
revised performance criteria.
This paper discusses the major effects of changes in grid code
requirements on generator machine design and the challenges
associated with meeting these requirements.
Index Terms-- Grid codes, generators, power system
transients.
I. INTRODUCTION
Working Group 8 of the IEEE Power and Energy Society
(PES), Electrical Machinery Committee (EMC) is comparing
the requirements for rotating machines specified in the most
widely used international standards IEEE C50.13 [1] and IEC
60034 [2], [3]. The objective is to identify opportunities for
harmonization of these documents to give a more uniform
basis for the design of rotating synchronous machines, in
particular generators operating in either 50 Hz or 60 Hz power
systems [6].
In the course of this work, topics have been identified in
which the requirements in the standards appear to be
diverging from the performance consistently expected from
customers worldwide in response to the evolving grid codes.
These have been termed ‘horizon issues’ [7].
The most recent changes in grid codes have been driven
predominantly by the introduction of more diverse and more
widely distributed power sources into power systems as part
of a global initiative to combat CO2 emissions. In particular
the growth in the installation of wind turbines has meant that
K. Mayor is with Alstom, Birr, Switzerland
(e-mail: [email protected]).
L. Montgomery is with Siemens Energy, Orlando, FL, USA
(e-mail: [email protected])
K. Hattori is with Hitachi Power Systems, Hitachi, Japan
(email [email protected])
J. Yagielski is with General Electric, Schenectady, NY, USA
(e-mail: [email protected])
978-1-4673-2729-9/12/$31.00 ©2012 IEEE
more demanding performance requirements have been
imposed to safeguard grid integrity and stability. These
requirements, however, are applied to all connected
equipment, leading to more stringent performance
requirements than have been needed in the past, and which are
reflected in the machine design standards IEEE C50.13 and
IEC 60034. This means that machines designed strictly in
accordance with these standards may not be able to meet the
current customer requirements without additional studies, and
possibly post development or project specific adaptation. New
generator product developments often therefore take into
account the more stringent requirements expected by the
market, and not simply those given in the standards.
This means that there is a clear need to review some of
these performance parameters in more detail and to update the
standards where necessary.
Additionally it has been questioned what degree of
consideration has been given to the impact on new or existing
connected plant when setting new grid code requirements.
In this paper, some of these ‘horizon issues’ are addressed
in more detail in order to give an insight into the impact of
certain performance parameters on the design of the rotating
electrical machine. The impact of grid code requirements
(such as low voltage ride through) on associated electrical and
mechanical auxiliary systems may also be significant, but are
beyond the scope of the machine standards and this paper.
This information is not intended to give design
methodology or criteria, but to form the basis of discussion
and common understanding between grid code legislators,
transmission system operators, plant owners and machine
designers in order to facilitate a common evolution of both
grid codes and machine design standards.
II. IMPACT OF GRID CODE REQUIREMENTS ON
MACHINE DESIGN PARAMETERS
In the following sections, specific aspects of machine
performance have been chosen to highlight some
discrepancies between current grid codes and the international
standards, and to illustrate the influence they can have on the
design.
A. Incompatibilities between Grid Codes and Generator
Standards – Voltage and Frequency Variation Limits
In the 2010 and 2011 papers [6], [7], WG 8 explained their
interest in the limits of voltage/frequency now being imposed
by some grid codes upon some turbine generators. Operating
at the extremes of limits in some grid codes can mean that the
involved generator will be subject to voltage and frequency
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excursions that go beyond limits defined in IEEE C50.13 and
IEC 60034-3. Both IEEE C50.13 and IEC 60034-3 now
require that generators shall be thermally capable of
continuous operation within the confines of their reactive
capability curves over the ranges of ±5% in voltage and ±2%
in frequency as defined by the red polygon in Fig. 1.
Fig. 1. IEEE C50.13 and IEC 60034-3 limits on voltage and frequency
Generators must also be capable of operation within the
confines of their reactive capability curves within the ranges
of ±5% in voltage and +3%/–5% in frequency as defined by
the blue polygon in Fig. 1, but with understood reductions of
insulation life and stability margins.
Challenges have recently arisen for power producers and
machine designers as grid codes have started to specify that
generators operate in a wider voltage and frequency range.
This change is happening in many locations in the world. Fig.
2 shows an example from one European grid code now in
force.
In this graph the limits specified for variations of grid
voltage and frequency are superimposed upon limits specified
by both IEEE C50.13 and IEC 60034-3 for variations of
generator voltage and frequency.
(Note: This example grid code does permit some reduced
power delivery limits and some short time limits for extremes
of voltage and frequency operation; however, for simplicity
these limits are not described in this paper.)
Fig. 2. Comparison of IEEE & IEC generator voltage-frequency limits
with grid voltage-frequency limits of one European Grid Code
To compare limits for frequency variation it is valid to
directly compare frequency ranges set by this grid code and by
generator standards because frequency is the same on both
sides of the step-up transformer. To comply with the above
grid code a turbine generator would be required to operate
with a ±5% frequency variation, which is broader than the
normal ±2% frequency variation and even broader than the
short term +3%/–5% frequency variation range defined by
IEEE C50.13 and IEC 60034-3. Implications of expanding
these limits include potentially compromising turbine
generator reliability, stability and performance. To overcome
these difficulties in designing a new turbine generator, a
design team must increase design margins and consequently
cause higher manufacturing costs. Qualifying in-service
turbine generators for the expanded frequency range is always
more difficult and is sometimes exceedingly more difficult
than doing so on a new unit design.
3
To compare limits for generator and grid voltage
variations, it is not valid to directly compare voltage ranges
specified by a grid code with voltage ranges specified by
generator standards. Grid codes specify voltage ranges for
grid voltage variations, and generator standards specify limits
for generator voltage variations; because of the intervening
reactance of the step-up transformer and because of varying
power factor operating conditions that are likely during
extremes of grid voltage, it is possible for a generator to
operate within its permissible ±5% voltage range (or at least
near to this range) while the grid voltage experiences extremes
of its permissible range. Generator active power and power
factor are influential. Discussion of this topic can benefit from
considering the simplified generator–grid connection diagram
shown in Fig. 3.
Fig. 3. Generator terminal conditions and grid conditions
Relationships between generator terminal voltage and grid
voltage on the high voltage side of the step-up transformer are
affected by active power, power factor, and transformer
reactance. For a 1000 MVA, 850 MW generator (rated power
factor = 0.85) and a transformer reactance of 15% on the
generator basis, at the extremes of the grid voltage range
shown in Fig. 2 the generator voltages shown in Table I would
be experienced.
TABLE I
GRID VOLTAGE & GENERATOR TERMINAL VOLTAGE FOR
VARYING GRID CONDITIONS
Grid Connection Point
Generator Terminals
Active Reactive
Grid
Gen
Gen
Gen
power
power
Voltage MVA Voltage power
[MW] [MVAR
[%]
[%]
[%]
factor
]
850
377
93
100
100
0.85
850
416
110
100
116
0.85
850
-388
110
89
105
-0.95
850
-477
85
89
78
-0.95
850
340
85
100
92
0.85
(Notes: The first row, shaded blue, is for generator rated
MVA, power factor & voltage operation, and negative power
factor means under-excited operation)
As shown in this table, operating the generator at rated load
and rated 0.85 overexcited power factor when the grid voltage
is at its uppermost limit causes excessive generator voltages
(data row 2, shaded red), and operating the generator at rated
load and rated 0.95 under-excited power factor when the grid
voltage is at its lower most limit causes excessive generator
currents (data row 4, shaded red).
Also shown is the fact that operating the generator overexcited when the grid voltage is low (data row 3, shaded
green) and operating the generator under-excited when the
grid voltage is high (data row 5, shaded green) can allow the
generator to operate within (or more nearly within) the ±5%
voltage range specified in IEEE and IEC standards. This point
was presented to CIGRE in 2004 at a panel session on grid
codes and generator standards [8].
Since operating a generator over-excited when grid voltage
is low and under-excited when grid voltage is high is
appropriate for grid security, and doing otherwise is
detrimental to grid security, then it is reasonable to require
power plant operators not to do otherwise. However it is
occasionally misunderstood that grid codes must be
interpreted to require power producers to be able to operate
their turbine generators at any point in the generator reactive
power capability diagram for any grid voltage condition. The
two red-highlighted rows in Table I (data rows 2 and 4) reveal
that it is in fact detrimental to generators to require that they
be operated under conditions that are detrimental to grid
security. It would be therefore advantageous if grid codes
could be adapted in such a way that this possible
misunderstanding can be avoided.
B. Volts/Frequency (V/f) short time capability requirements
The machine voltage V is determined by (1):
V = –dφ/dt = -2 π f φ
(1)
where,
dφ/dt is the rate of change of magnetic flux,
f is the frequency of the flux,
φ is the flux sweeping across the stator conductors.
V/f therefore represents the magnetic flux, φ, or the
magnetic flux density, B, in the stator core. From the
generator side, the maximum value of B is determined by the
dimensions and material properties of the stator core. If the
flux density exceeds a certain value, then the stator core
cannot shield the magnetic flux resulting in some flux
penetrating the stator core. This leakage flux links the outer
components of the core support structure. Figures 4 and 5
show the magnetic flux distribution for rated V/f, and for a
larger V/f respectively.
Fig. 4. Magnetic flux distribution at rated condition
4
Alternatively a basic design change to achieve a larger
SCR is to enlarge the air-gap between the stator and the rotor
as shown in Fig. 7.
Fig. 5. Magnetic flux distribution with larger V/f condition
Fig. 7. Image of the SCR and generator dimension for a standard SCR (left)
and an increased SCR (right); same rotor diameter
Fig. 6. Leakage flux and circulating current in the stator core structure
When the leakage flux links the outer support structure,
circulating currents will flow in such a manner that the current
produces a counter magnetic flux to cancel the linkage (Fig.
6). If these currents become sufficiently high, then
overheating or other damage could occur to the outer
components. The larger the V/f value is, the shorter the time
the generator can withstand it without damage.
As explained above, the core material determines the
maximum available flux density, B, and, if a higher value of
V/f than is specified by IEEE C50.13 is required, then more
iron is required to keep the flux density within the allowable
range. This will make the generator heavier and therefore
more expensive to manufacture and transport.
C. Short circuit ratio
Short circuit ratio (SCR) is specified as “The ratio of the
field current for rated armature voltage on open-circuit to the
field current for rated armature current on sustained
symmetrical short circuit, both with the machine running at
rated speed”
When a larger SCR is required, a practical approach is to
adopt a generator in a larger output range because the field
current required for rated short circuit current is proportional
to the generator output while the field current for the opencircuit condition remains constant if the voltage is not
changed. In this case, the temperature rise of the stator and
rotor will be reduced (because it is effectively de-rated)
allowing the size of the generator to be optimized as long as
the temperature remains within the allowable range.
Because the magnetic reluctance at the air gap is larger, the
required field current to achieve rated voltage is larger.
However, the field current for rated armature current on short
circuit doesn’t change because the magnetic fluxes are
balanced out in the air gap when short-circuited. If the
temperature of the rotor in the original design is not low
enough for this increased field current, then the rotor cooling
has to be augmented, which requires further design change in
a way that the rotor could get larger in dimension.
Consequently, the ventilation and windage losses of the
generator would also be larger.
Table II gives, as an example, a comparison of generator size
and SCR for the two alternative design approaches mentioned
above. The base generator is a design having a SCR of 0.5. If
a SCR of 0.8 is required, then a generator design from a
higher output range could be chosen (case 1). In this case, the
design has 35% higher weight and consequently higher cost
because the basic dimensions remained unchanged in order to
utilize existing design documentation from standard product
lines.
When a generator design with an increased air gap is
chosen (case 2), the design results in higher rotor
temperatures, which may then need further optimization. In
this approach, the same increased SCR was achieved for a
smaller weight increase of 17% when the specified value of
rotor temperature was achieved. This design, however, is very
different from the base generator and would therefore require
additional effort to design and manufacture it as a special
product.
TABLE II
IMPACT OF INCREASED SCR ON GENERATOR WEIGHT
Base
Generator
Capacity
SCR
Weight of
Main Parts
MVA
%
230
0.5
100
Case 1
Higher
output
range
230
0.8
135
Case 2
Larger
air gap
230
0.8
117
5
D. Rapid reclosing
Standard IEEE C50.13 [1] describes the effects of rapid
reclosing following system faults with respect to causing high
torques in turbogenerator / turbine shafts, where successful
and unsuccessful rapid reclosure events are of potential
concern. The standard concludes that, “Because of the
statistical nature of the system torques and local shaft torques
and the cumulative effect of the resulting fatigue damage to
shafts, generalized requirements are not possible. Where it is
expected that a turbogenerator is to be subject to power
system rapid reclosures, it is recommended that the
manufacturer be consulted and a possible unit-specific study
be performed.”.
The impact / effect of rapid reclosing on the turbogenerator
shaft line, with respect to currents, forces and
electrical/mechanical torques, depends on several factors [9],
[10], [11], e.g.
(a) The properties of reclosing, grid configuration and system
faults such as:
- the type of auto-reclosing: rapid or delayed,
- the method of reclosing: single phase or three-phase,
- the time delays of the reclosing,
- successful or unsuccessful reclosure,
- nature of the system faults
(single phase to ground, phase-to-phase, two phase to
ground, three-phase to ground or not),
- the location of the system fault
(close to the plant or remote in the meshed grid),
- the application of a synchrocheck, which limits on the
reclosing angle,
- the grid configuration
(short circuit power, transmission line reactances),
- the fault clearing times of the primary protection,
- the applied reclosing schemes, e.g. blocking of reclosing
in case of breaker failure protection.
(b) The plant parameters and design (step-up transformer,
turbogenerator, gas and/or steam turbines) such as:
- the characteristic parameters (e.g. reactances) of the
generator including exciter with automatic voltage control
and the step-up transformer,
- the characteristic parameters of the steam and/or gas
turbines (e.g. Torsional eigenfrequencies, inertia,
torsional stiffness, mechanical damping values of the
shaft line model)
- the design of the turbogenerator (e.g. stator, stator
winding, rotor, rotor windings)
- the design of the exciter (brush gear or rotating exciter)
- the design of the shaft sections of generator, exciter,
couplings, steam and gas turbine
- the design of the generator – turbine shaft configuration
(single shaft or multi shaft)
The major effects of auto-reclosing on turbogenerators
(rapid or delayed) are:
- high mechanical torques / stress in the generator and
exciter shafts,
- high forces / stress on generator windings (especially endwinding parts).
The conditions for auto-reclosing should be clarified with
the plant owner and manufacturer in case auto-reclosing (rapid
or delayed) is specified.
As described above, the impact of auto-reclosing on
turbogenerators depends on many different factors. Therefore
investigations aiming to reduce this impact should take all
these factors into consideration.
Modification or adaptation of the generator design to cope
with the reclosing conditions on any specific network, e.g.
shaft line inertia, stiffness, cross-section or electrical
parameters can lead to additional design work, postdevelopment and possible increased cost. Therefore some of
the other factors (e.g. increasing the reclosing time and/or the
use of a synchrocheck relay) [12] may be more easily realized
than further modifications of a turbogenerator shaft line, that
is already optimized to fulfill many electrical, thermal,
mechanical, and environmental requirements. This is
especially so in the case of upgrades or refitting of existing
plant.
E. Impact of harmonic currents impressed on the turbogenerator – Reduction of negative sequence capability.
The minimum requirements for the negative phase
sequence capability of generators is defined in IEEE and IEC
international machine design standards [1], [2], and [3] which,
as already highlighted [6], show a discrepancy in the
minimum requirements. It has been proposed that these
requirements need to be reviewed to allow a consistent
approach, bearing in mind the different heating effects when
operating on a 50 Hz or 60 Hz system.
If the harmonics imposed by the system exceed normally
assumed values, then these also need to taken into account in
the generator performance assessment, possibly resulting in a
decrease in the negative sequence capability that can be
declared for that specific application.
The total harmonic distortion (THD) of the grid voltage is
defined in both IEEE and IEC standards [4], [5]. These
specify 1.5% (IEEE) and 3% (IEC) respectively for a nominal
grid voltage of 220 kV. Specifications above these values
therefore need to be considered for the additional heating
effect they will have on the rotor surface.
Voltage distortion, or in other words voltage harmonics,
has an impact on the rotor damper losses because each of the
voltage harmonics produces a stator current harmonic which is
not in synchronism with the rotor movement and therefore
produces currents and losses in the damper system and on the
rotor surface. Fig. 8 shows a magnetic field plot of an
analytical calculation of such a harmonic.
6
Fig. 8. Typical magnetic field plot from an analytical calculation of a stator
current harmonic
The central area is the rotor, outside of which is the air gap,
the stator slot/tooth section, with the outer annulus
representing the stator yoke. It can be seen that the flux and
current is concentrated at the rotor surface.
The equivalent heating effect of high THD requirements is
calculated by transforming the voltage time harmonics into a
stator current time harmonic for each harmonic order.
The stator current time harmonic produces a magnetic field in
space that has the same distribution as the fundamental
magnetic system (time harmonics in the 3-phase stator current
system have the same space distribution as the fundamental).
The same current system is induced on the rotor surface as it
is existing in the stator, because it is not in synchronism with
the rotor movement. From this the corresponding equivalent
rotor current time harmonic can be derived (current
corresponding to the stator slot pitch on the rotor surface
weighted by a factor to take into account the different
frequencies). The total harmonic equivalent negative sequence
current on the rotor, can then be calculated using (2):
iharmonics _ rotor =
iν
∑
ν
2
Rotor
= i52Rotor + i72Rotor + i112 Rotor + ... (2)
where,
I harmonics rotor = total harmonic equivalent negative sequence
current on the rotor
I νRrotor = corresponding equivalent rotor current time
harmonic
In order to calculate the total harmonic equivalent negative
sequence current on the rotor, the formula (3) can be applied:
2
2
itotal _ rotor = iharmonics
_ rotor + i negative _ sequence
(3)
where inegative _ sequence is the allowed continuous negative
sequence current component according to the IEEE / IEC
standards.
Typically the standard levels of THD given above will
result in an additional heating of the rotor surface of up to
10% depending on the voltage levels. This can be considered
an acceptable level of additional heating and complying with
the combined negative sequence and THD limits defined in
the standards.
If the additional heating of the rotor due to the imposed
stator THD harmonics is too high, then a reduction in the
declared negative sequence capability must be imposed, or
additional measures taken to deal with the additional
circulating currents in the rotor surface, e.g. fitting pole face
dampers, modifying the damper concept, modifying the inertia
compensation features (e.g. slitting of the pole face), or even
offering a larger machine size.
Generators designed according to the IEEE and IEC
standards may not be capable of meeting an increased level of
combined THD and continuous negative sequence current
component without careful review and possible design
adaptation. This should be recognized when specifying
increased levels of THD in grid codes, and future revisions of
the standards should consider guidelines to evaluate this
impact on the declared negative sequence capability.
F. Low voltage ride through during system faults
The variation in grid codes regarding low voltage ride
through (LVRT) requirements is large, and, with the
increasing addition of distributed power sources within
transmission systems, these requirements are placing ever
more challenging demands on the performance of both
existing and new generators [13], [14].
The diversity of LVRT requirements within European grid
codes has led to a harmonization initiative [15]. Whilst the
requirements can be clarified and harmonized, they remain a
challenge to the generator designer, and can lead to bespoke
tailoring of the generator design specifically to meet them.
The main influencing factors affecting the ability of the
generator to successfully recover from an LVRT event are:
· the initial operating conditions,
· the pre- and post fault conditions of the system,
· the connecting reactance,
· the specific low voltage ride through requirement,
· the main generator parameters.
If the system parameters cannot be adjusted, then the
generator design may have to be adapted to achieve the
required response. Sensitivity studies [13] carried out for a
typical turbogenerator have highlighted the effect of specific
parameters on the ability of a generator to successfully ride
through low voltage events. A summary is given in Table III.
The figures shown in bold indicate that the critical clearing
time in milliseconds is sufficient to meet the specified
requirements. This shows that, to meet specific LVRT
requirements, an increase in rotor inertia, short circuit ratio or
excitation ceiling factor, or a combination of all three, could
be required.
7
TABLE III
SENSITIVITY OF THE CRITICAL CLEARING TIME (MS) OF A LOW VOLTAGE FAULT
TO SPECIFIC MACHINE AND SYSTEM PARAMETERS
Generators designed according to standards IEEE C50.13 or
IEC 60034-3 to withstand sudden short-circuits do not
therefore automatically comply with the fault ride through
requirements. These requirements may impact the generator
design parameters such as inertia, short-circuit ratio, voltage
ceiling factors, transient reactances, etc. Such modifications to
an existing generator design will, in turn, lead to some post
development, increased size, increased delivery time and
ultimately increased cost which must be borne by the
purchaser.
G. Ceiling Voltage – impact of ultra high ceiling voltages on
rotor insulation system.
One of the possibilities mentioned above to improve the
LVRT capability is to increase the ceiling voltage of the
excitation system. This in turn impacts the demands on the
rotor insulation system.
Rotor insulation systems are crucial to the reliability of a
turbo-generator, and are exposed to significant mechanical
duty during assembly of the windings and during operation. In
addition, excitation systems with high ceiling voltages may
impose additional duty on the field winding insulation system.
High-response static excitation systems frequently operate
with full ceiling voltage applied to their AC or source side.
The appropriate level of average DC voltage is controlled by
the firing angle of the rectifier bridges. The field winding will
be exposed to full AC voltage levels and switching spikes that
reach the field ceiling voltage several times per cycle. Fig. 9
compares the field voltage waveform of two different
excitation systems, one with a higher ceiling voltage than the
other. In both cases, the average field voltage is the same.
These switching spikes appear across the materials that
insulate the winding from the rotor shaft. Voltage spikes are
also imposed on the air gaps and creepage paths associated
with direct-cooled windings. Based on the distribution of
voltage throughout the field winding, the turn insulation
system is also subject to high frequency voltage spikes. Both
may necessitate thicker insulating components, reducing the
space available for conductor, and potentially increasing
losses.
Fig. 9. Field voltage waveforms for two excitation systems
In addition to the impact on the field winding insulation
system, higher ceiling voltages raise the secondary voltage of
the exciter input transformer. This yields a higher transformer
rating, size and cost, along with increased losses.
III. CONCLUSION
In recent years, due to the progressive introduction of
intermittent and more diverse and distributed power sources
(in particular wind turbines), the grid codes in many countries
have evolved in order to safeguard the integrity and stability
of the power networks. This evolution has resulted in
increasing demands put on the performance of the other
electrical equipment, both existing and new, connected to the
same system. These increasing demands have a direct impact
on the detail design of those components, and this paper has
explained the impact of specific aspects of turbogenerator
performance parameters.
Turbogenerators are fundamentally designed to meet the
requirements as specified in international standards, which are
intended to represent the basic requirements of the most
common applications within the power supply industry. As
grid code requirements and customer needs evolve, there is a
need for these standards also to evolve, otherwise machines
designed strictly in accordance with their requirements can no
longer be relied upon to automatically fulfill the normal
expectations of customers without additional study, and
possibly design adaptation or post development.
As illustrated in this paper, such design adaptations
generally lead to more complicated or simply bigger machine
designs that directly affect the cost of new equipment. On an
existing plant, such design adaptations may not be possible
without major rework or replacement.
8
By highlighting the impact of changes in grid code
requirements specifically on turbogenerator designs, IEEE
EMC Working Group 8 seeks to facilitate a common
understanding and open discussion between the various
legislators, operators, owners and designers of the challenges
faced in meeting these more exacting demands, and to draw
attention to specific areas where the traditional design
standards no longer reflect the industry needs. In this way it
seeks not only to encourage dialogue and compromise
between the parties, but also to identify and initiate future
adaptations to the design standards such that common design
practice and customer needs can evolve in unison.
IV. ACKNOWLEDGMENT
The authors gratefully acknowledge the contributions of J.
Haldemann, J. Heil, and I. El-Merdoui in the preparation of
this paper.
V. REFERENCES
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[1]
IEEE Standard for Cylindrical-Rotor 50 and 60 Hz Synchronous
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IEC 60034-1: Rotating Electric Machines – Part 1: Rating and
Performance, Revision 11, 2004.
IEC 60034-3: Rotating Electric Machines – Part 3: Specific
Requirements for Cylindrical Rotor Synchronous Machines, Revision 6,
2007
IEEE Standard 519: Recommended practices and requirements for
harmonic control in electrical power systems, 1992
IEC/TR standard 61000-3-6, Electromagnetic compatibility (EMC) Part 3-6 : limits - Assessment of emission limits for the connection of
distorting installations to MV, HV and EHV power systems, 2008
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IEEE Screening Guide for Planned Steady-State Switching Operations to
Minimize Harmful Effects on Steam Turbine-Generators. IEEE
Transactions on Power Apparatus and Systems, Vol. PAS-99, No. 4
July/Aug 1980.
L. Rouco, C. Ginet, K. Chan, K. Mayor, O. Malcher, L. Díez-Maroto, R.
Cherkaoui, “Voltage ride through capability of synchronous generators:
Grid code requirements and sensitivity with respect to their parameters”,
CIGRE Study Committee A1 Meeting, Sydney (Australia), 21-24
September 2009.
[14] L. Rouco, C. Ginet, K. Chan, K. Mayor, O. Malcher, L. Díez-Maroto, R.
Cherkaoui, “Improvement of the voltage ride through capability of
synchronous generators by excitation control”. CIGRE session 43, Paper
A1-106, Paris (France), 22-27 August 2010.
[15] L. Rouco, K. Chan, S. Keller, J. Oesterheld, “Recent Evolution of
European Grid Code Requirements and its Impact on Turbogenerator
Design”, IEEE PES meeting San Diego, July 2012.
VI. BIOGRAPHIES
Kevin Mayor received a BA degree in
Engineering from Cambridge University, England
in 1981. Since then he has been involved in the
design and development of large turbogenerators of
all types. At present he is an Expert Engineer in
Alstom in Birr, Switzerland, a member and current
secretary of the IEEE PES Electric Machinery
Committee, and a member of the Generator
Subcommittee of the EMC. He is a member of
CIGRE and presently represents Switzerland in
Study Committee A1 ‘Rotating Machines’.
Lon W. Montgomery received a BS degree in
Electrical Engineering from Carnegie-Mellon
University in 1968, an MSEE degree in Electrical
Engineering from The Johns Hopkins University in
1970, and an MSME from Carnegie-Mellon
University in 1976. In 1968 he joined Westinghouse
Electric Corporation. Since 1970 he has concentrated
on electric machine design. At present he is a
Principal Expert Engineer in Siemens Energy in
Orlando, FL. He is a recently elected Fellow of the
IEEE, a member of the IEEE PES Electric Machinery Committee, and a
member and past chairman of the Generator Subcommittee of the EMC. He
has served on several recent EMC/GSC Working Groups that were convened
to maintain and improve IEEE standards for large turbo generators. In one
instance he served as vice-chair of the WG to modernize IEEE C50.13-2005
and harmonizes its content with the IEC 60034 series for large turbo
generators.
Kenichi Hattori received the BS degree in
Electrical Engineering from Doshisha University in
Kyoto in 1990, and the MSEE in 1992. He has been
working for turbo generators in Hitachi, Ltd. His
profession is in thermal/ventilation calculation as
well as electrical design. He is now in charge of
development. He is a member of IEC/TC2/WG12 as
well as an assistant secretary of the Japanese
national committee of IEC/TC2 and a secretary of
the Japanese national committee of CIGRÉ.
John R Yagielski has been an IEEE member for 16
years, and a graduate of Clarkson University (BSEE
’90) and Rensselaer (MSEE ’93). He has worked at
General Electric in Schenectady, New York since
1990 in generator design engineering and
manufacturing quality, most recently as a Technical
Leader for high speed electric machines. Mr.
Yagielski is a Registered Professional Engineer in
New York State.