IEEE Power & Energy Society
November 2018
TECHNICAL REPORT
PES-TR69
REPORT ON COORDINATION OF GRID
CODES AND GENERATOR STANDARDS:
Consequences of Diverse Grid Code
Requirements on Synchronous Machine
Design and Standards
PREPARED BY THE
Electrical Machinery Committee Task Force on
Grid Code Impacts on Generator Standards
© IEEE 2018 The Institute of Electrical and Electronics Engineers, Inc.
No part of this publication may be reproduced in any form, in an electronic retrieval system or otherwise, without the prior written permission of the publisher.
TR-69 — Grid Code Impacts on Generator Standards
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TR-69 — Grid Code Impacts on Generator Standards
Electrical Machinery Committee
Task Force on Grid Code Impacts on Generator Standards
Report on Coordination of Grid Codes and Generator Standards:
Consequences of Diverse Grid Code Requirements on
Synchronous Machine Design and Standards
Chair: Robert Thornton-Jones
Members and Contributors
Evert Agneholm, William Bloethe, Edson Bortoni, Kevin Chan,
Kay Chen, Bob Cummings, Robert F. Gray, Randall Groves,
Les Hajagos, Joe Hurley, Relu Ilie, Chavdar Ivanov, Ana Joswig, Jason Kapelina,
Ruediger Kutzner, Jim Lau, Kevin Mayor, Bill Moore, Lon Montgomery,
Nils Nilsson, Ryan Quint, Steve Richards, Michel Rioual, Luis Rouco, Mike Sedlak,
Uwe Seeger, Nico Smit, Fabian Streiff, Robert Thornton-Jones,
John Yagielski, Marc Zeidman, Carsten Zuehlke
ACKNOWLEDGMENTS
The Task Force gratefully acknowledges the principal authors/contributors of the following
sections:
•
•
•
•
Section 3.1: Kevin Chan, Kevin Mayor
Section 3.2: Luis Rouco, Kevin Chan
Section 3.3: Les Hajagos, Uwe Seeger
Section 3.4: Jim Lau, Relu Ilie, Lon Montgomery, JohnYagielski,
KEYWORDS
Grid Code, Generator, Synchronous Machine, Standard, Capability, Fault Ride Through,
Operational Flexibility
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TR-69 — Grid Code Impacts on Generator Standards
CONTENTS
1. INTRODUCTION ....................................................................................................... 1
2. THE PRESENT STATUS OF GRID CODES AND STANDARDS .............................. 3
3. DIFFERENT FACETS OF GRID CODES AND THE ENERGY TRANSITION ........... 5
3.1
Generator Capability Envelope and Design Challenges .................................... 5
3.1.1
Voltage-Frequency Operating Ranges ....................................................... 5
3.1.2
Reactive Power Capability ......................................................................... 8
3.1.3
Short-Circuit Ratio (SCR) ......................................................................... 11
3.1.4
Conclusions and Recommendations on Capability Envelope ................... 13
3.2
System Fault Related Requirements ............................................................... 15
3.2.1
Impacts of System Faults on Generators and Power Plant Response ...... 15
3.2.2
Single Fault Ride Through Capability ....................................................... 15
3.2.3
Multiple Fault Ride Through Capability ..................................................... 22
3.2.4
Rate of Change of Frequency (RoCoF) .................................................... 25
3.2.5
Auto Re-Closing ....................................................................................... 28
3.2.6
Maximum Power Output vs. Frequency.................................................... 30
3.2.7
Conclusions and Recommendations on Fault Related Issues .................. 33
3.3
Generator Excitation Systems......................................................................... 36
3.3.1
Introduction .............................................................................................. 36
3.3.2
Excitation System Power Equipment Design ............................................ 36
3.3.3
Excitation System Functional Design ....................................................... 45
3.3.4
Excitation System Grid Code Applicability & Acceptance Procedures ...... 55
3.3.5
Conclusions and Recommendations on Excitation Related Issues........... 57
3.4
Operating New and Existing Generators to Support the Energy Transition ..... 58
3.4.1
New Service Factor Requirements ........................................................... 58
3.4.2
New Duty Cycle Requirements ................................................................ 59
3.4.3
Existing Generators Flexibility Requirements in Grid Codes..................... 61
3.4.4
Possible damage scenarios ..................................................................... 61
3.4.4.1 The Effects of Frequent Starts and Stops ................................................. 61
3.4.4.2 The Effects of Load Ramps ...................................................................... 62
3.4.4.3 The Effects of Power Factor ..................................................................... 62
3.4.4.4 The Effects of Steady State Conditions .................................................... 62
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TR-69 — Grid Code Impacts on Generator Standards
3.4.4.5 The Effects of High Voltage at Low Speed ............................................... 63
3.4.4.6 The Effects of Voltage Variations ............................................................. 63
3.4.4.7 The Effects of Frequency Variations ........................................................ 63
3.4.4.8 The Effects of Fault-Ride-Through ........................................................... 63
3.4.4.9 The Effects of Ceiling Voltage .................................................................. 64
3.4.4.10
The Effects of High Speed Reclosing ................................................ 64
3.4.4.11
The Effects of Harmonic Currents ..................................................... 64
3.4.4.12
The Effects of Other Factors Including Steady State Conditions ....... 65
3.4.5
Impact on Efficiency ................................................................................. 65
3.4.6
Data Gathered Demonstrating the Effects of New Grid Demands ............ 67
3.4.7
Conclusions on Operating Generators to Support the Energy Transition.. 69
4. OVERALL CONCLUSIONS AND RECOMMENDATIONS ....................................... 71
4.1
Recommendations: Suggestions for Grid Codes............................................. 71
4.1.1
Capability Envelope ................................................................................. 71
4.1.2
System Faults .......................................................................................... 71
4.1.3
Excitation Systems ................................................................................... 72
4.2
Recommendations: Suggestions for Standards .............................................. 72
4.2.1
Capability Envelope ................................................................................. 72
4.2.2
System Faults .......................................................................................... 72
4.2.3
Excitation Systems ................................................................................... 73
4.2.4
Operational Flexibility ............................................................................... 73
4.3
Recommendations: Awareness for Stakeholders ............................................ 73
4.3.1
Capability Envelope ................................................................................. 73
4.3.2
System Faults .......................................................................................... 73
4.3.3
Excitation Systems ................................................................................... 74
4.3.4
Operation of Existing Generators and the Need for Operational Flexibility75
4.3.5
Call to Action ............................................................................................ 75
5. ACKNOWLEDGEMENTS ........................................................................................ 76
6. REFERENCES ........................................................................................................ 77
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1.
INTRODUCTION
The recent energy transition towards large-scale integration of renewable energy sources
into the electrical supply system to combat global CO2 emissions across the world is
leading grid operators to specify more stringent operation and flexibility requirements for
generating equipment to safeguard the power grid operational integrity and stability. This
is causing a significant impact for generator owners and manufacturers and for those
responsible for designing generators and excitation systems. To avoid serious financial
consequences, these stakeholders need to ensure that equipment will be grid code
compliant and to ensure that equipment is not damaged by new modes of operation.
On considering those concerns, the IEEE PES Electric Machinery Committee (EMC)
established a task force to investigate and report on impacts of worldwide grid codes on
generator standards. This task force has reviewed over 30 diverse grid code documents
from around the world and has created this report to present key data, discussion and
recommendations resulting from that review.
The report mainly uses the term grid code to refer to legally imposed requirements on
generating units and their equipment. In many countries, grid codes are national laws. In
North America, NERC (North American Electric Reliability Corporation) develops
Reliability Standards; in the United States, FERC (Federal Energy Regulatory
Commission) facilitates the pro forma large and small generator interconnection
agreements (LGIA/SGIA); and in Europe ENTSO-E (European Network of Transmission
System Operators for Electricity) is the entity authorized to develop network codes which
are issued as European Regulations that supersede national laws.
The task force also reviewed international equipment standards. Traditionally generators
have been designed according to IEEE standard C50.13 [1] and the IEC 60034 [2], [3]
standards which for many years have provided technical guidance to manufacturers and
purchasers of equipment to ensure that requirements and performance meet market needs.
In a deregulated electricity market, different interests of the market players have required
clearly defined connection requirements to ensure the stability of supply, as stipulated in
national grid codes. A comprehensive survey of grid codes by CIGRE [5] has shown that
they all extend or diverge from the technical requirements of equipment as specified by
standards. Furthermore, the requirements in the various national grid codes are not
harmonized, leading to many generator design modifications and challenges to fulfill the
needs of each national market.
Machines designed strictly in accordance with the afore-mentioned technical standards
may not be able to meet the most recent grid code requirements without additional studies,
and possibly post development or project specific adaptation. Therefore, the task force
considered recommending enhancements to these standards with the aim of using the
standards to more easily accommodate diverse grid code requirements.
It is important to understand that the energy transition is not only driving changes to grid
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TR-69 — Grid Code Impacts on Generator Standards
codes but it is also causing equipment to be subjected to increased stress in service.
Therefore, a reduction of lifetime of power generation equipment, which could be up to 5
years [78], is likely to become a significant problem. As a consequence, it is the opinion of
this task force that there is a clear need for grid operators, power producers and equipment
manufacturers to agree on harmonized requirements in grid codes and technical standards
to ensure that generating equipment connected to the grid meets the desired technical and
economic criteria.
This report is organized with the following sections:
In section 2 of this report, a short discussion is provided on the current changes in the
electrical supply system related to generation mix and introduction of new technologies
affecting system performance, operational procedures, and possible risks of system
disturbances and interactions on control systems. A correlation of these changes and the
affected areas in the electrical supply system can be traced to additional flexibility
requirements, and to more stringent requirements for generating equipment that are
appearing in the majority of existing grid codes.
The focus of section 3.1 is on issues related to the generator capability envelope as specified
in the technical standards and design challenges to accommodate current and future grid
code requirements faced by equipment manufacturers.
The impact of system fault related requirements on generator design and standards is
discussed in section 3.2. Fault Ride Through, Rate of Change of Frequency, Maximum
Power Output vs. Frequency, and Auto Re-closing requirements and their impact on
generator design are covered in detail.
In section 3.3, the impact of grid code requirements on the generator excitation system and
the related equipment standards are addressed. Topics discussed include the impact on
hardware and functionality designs, reactive power coordination and the applicability of
these requirements.
The rapid integration of renewables and the changing generation mix have resulted in
existing and new generators being operated in ways for which they were not originally
designed. In addition, new requirements imposed by current grid codes may not have been
considered during the design of these existing generators. Section 3.4 discusses the
influence of current grid codes’ requirements as well as the tendency of system operators
to apply flexible operation regimes to existing generators. The impact on efficiency
because of these operational flexibility regimes is also covered in this section.
Conclusions and recommendations are discussed in section 4. Recommendations on how
to overcome some of the design challenges and the needs to facilitate dialogues between
all stakeholders of grid codes and technical standards are highlighted.
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TR-69 — Grid Code Impacts on Generator Standards
2.
THE PRESENT STATUS OF GRID CODES AND
STANDARDS
The de-regulation of electricity markets has resulted in the unbundling of vertically
integrated utilities into generation, transmission, and distribution companies.
Consequently, grid codes have been developed by Transmission System Operators (TSOs)
to formalize their obligations and to establish the framework of their technical relationships
with generation and distribution companies. In many countries, grid codes are now legally
binding in the region or country to which they apply.
Standards are tools for technical interaction between manufacturers and customers. As
these standards are widely accepted, compliance with them gives manufacturers the
confidence necessary to develop products which will be acceptable for a wide range of
customers. This approach allows the dual benefits for the market of costs being controlled
to a reasonable level, and equipment reliability being high as a consequence of a large fleet
experience.
For many years, manufacturers have been developing generators per IEC and IEEE
standards. However, it is becoming increasingly difficult to fulfill the grid code
requirements of some countries and regions because these requirements go far beyond what
is required by IEC and IEEE standards.
The physical properties and dynamic performance of a power system is largely dependent
on the type, volume and location of the connected generators and loads as well as the degree
of electrical interconnection between them. Amongst other anticipated changes, the volume
of non-synchronous generation (wind and solar photovoltaic power plants and
interconnectors) connected to the system is expected to continue to increase rapidly and
significantly over the coming decades resulting in:
•
•
•
•
•
•
•
Changes in system inertia;
Reduction in system short circuit level;
Greater variability of power flows;
Changes in generation and demand characteristics.
Changes in system damping and susceptibility to device interactions;
Dynamic control challenges associated with new and existing technologies; and
Changes in steady state voltage and frequency seen by generators and
transformers
Consequently, there will be an impact on how power systems can be operated to maintain
system stability and asset ratings, as well as operational parameters, within pre-defined
limits safely, economically, and sustainably. Taking the UK power system as an example,
Fig. 1 [6] summarizes changing grid characteristics and the affected areas of system
operation. In general, such impact and consequences are applicable for all power systems.
To ensure that electrical supply systems can be operated in a stable and reliable manner
amid the abovementioned changes, system operators have taken steps to define technical
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TR-69 — Grid Code Impacts on Generator Standards
connection requirements for generators that must be complied with to operate in the power
system. These typical grid code requirements include:
•
•
•
•
•
•
•
•
Voltage-frequency operating ranges and durations;
Reactive power capability;
Generator short-circuit ratio (SCR);
Fault ride through;
Rate of Change of Frequency (RoCoF) withstand capability;
Excitation voltage ceiling factor;
Auto-reclosing;
Power output versus frequency.
In the following sections of this report, each of these grid code requirements will be
compared with what is specified in technical standards.
Fig. 1. Changes in power system and affected areas
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TR-69 — Grid Code Impacts on Generator Standards
3.
DIFFERENT FACETS OF GRID CODES AND THE ENERGY
TRANSITION
3.1
Generator Capability Envelope and Design Challenges
3.1.1 Voltage-Frequency Operating Ranges
IEEE C50.13 [1] and IEC 60034-3 [3] specify that generators shall be thermally capable
of continuous operation over the ranges of ±5% in voltage and ±2% in frequency as defined
by the shaded zone in Fig. 2.
Fig. 2. IEEE C50.13 and IEC60034-3 limits on voltage and frequency.
Generators are normally connected to transmission systems via step up transformers and
grid codes typically refer to the voltage at the grid connection point, see Fig. 3, which is not
the voltage at the terminals of the generator. As an example, the grid voltage may reach a
value of 1.06 p.u., while the generator voltage may reach a value of 1.08 p.u. For a 900
MW nuclear plant, grid side voltage may be 400 kV, while 1 p.u. generator terminal voltage
is 24 kV.
Generators must also be capable of operation within the ranges of ±5% in voltage and
+3%/–5% in frequency as defined by the outer dashed boundary in Fig. 2 but should be
limited in extent, duration and frequency to minimize the reduction of life.
However, the majority of grid code requirements extend beyond the voltage-frequency
operating range presented in Fig. 2. An example of the requirement [7], the Nordic grid
code is shown in Fig. 3 indicated by the rectangular boundaries.
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TR-69 — Grid Code Impacts on Generator Standards
Fig. 3. Example of IEC/IEEE requirements vs. requirements of the Nordic grid code.
A further example is the requirement from the new EU Network Code Requirements for
generators [10] as shown in Fig. 4.
Fig. 4. Requirements of the new EU network code
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TR-69 — Grid Code Impacts on Generator Standards
The voltage-frequency operating ranges in grid codes often:
•
•
•
•
Require ranges that are significantly larger than in equipment standards;
Are not harmonized amongst the various grid codes;
Do not clearly define boundary conditions of operation (e.g. reactive load,
duration of disturbance, frequency of occurrence);
Define voltage ranges at the power plant connection point, hence the
corresponding generator terminal voltage excursions are unclear to the OEM
without prior knowledge of
o The generator step-up transformer reactance; and
o Whether an on-load tap changer (OLTC) is fitted to the transformer.
Machine manufacturers must contend with many design challenges that may not be
economically viable or practical, to fulfill the voltage-frequency operating ranges as
defined in all grid codes. When the requirements in the grid codes are not harmonized, it
is difficult to design standard generators for standard turbines increasing the engineering
as well as manufacturing efforts. These extra efforts translate to increase cost impact on
the generator. Even if the equipment can be manufactured to meet the enlarged V-f ranges,
outcome of the design will lead to oversized machines.
The task force recognizes that transmission system operators (TSOs) generate the rules for
the future energy mix and the conditions for the different generating plants (wind, solar,
nuclear, thermal) to be connected. Furthermore, harmonization may be difficult
considering the different kinds of electrical systems, the operating conditions, etc.
Discussions between the different stakeholders will be essential to improve the common
knowledge and provide solutions.
Articles [8],[9] [8] have discussed, the increased risk of stator over-fluxing when a
generator is operated at an enlarged frequency range (95% - 103%, i.e. 47.5 Hz - 51.5 Hz
in Europe) and a wider voltage range (85% - 115%), as required by the European Network
Code. Higher flux density equates to overheating risks for the generator and can result in
severe and even catastrophic damage to the generator. A catastrophic failure of a generator
by stator over-fluxing (see Fig. 5) occurs every few years (on average), and this increased
risk due to operation at higher frequency ranges and elevated voltage ranges will certainly
exacerbate this problem.
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TR-69 — Grid Code Impacts on Generator Standards
Fig. 5 Core Catastrophic failure due to stator over-flux [79].
3.1.2 Reactive Power Capability
Both IEEE C50.13 [1] and IEC60034-3 [3] specify a range of standardized over-excited
power factors of 0.80, 0.85, 0.90, depending on the type of cooling. IEEE C50.13
recommends 0.85 or 0.9 for hydrogen-cooled generators, with a default value of 0.9 if not
specified. Other values may be agreed upon, but the lower the power factor the larger the
machine will be. Under-excitation capability is standardized at 0.95 at rated power output.
All power factors are specified at generator terminals. In many grid codes, the generator’s
power factor or reactive power capability is specified at the point of connection on the
transmission system (instead of at generator terminals, as in the generator standards). These
two power factors are different, because of reactive power absorbed by the unit main
transformer (plus the small power consumed by auxiliary loads). For instance, a grid code
specifying 0.9 over-excited (lagging) to 0.9 under-excited (leading) power factors may
imply a generator with 0.85 lagging to 0.95 leading capability is required depending on the
generator step-up transformer. In the European Network Code [10], for example, reactive
power capability is specified as a ratio between the reactive power and the maximum active
power (Q/Pmax) delivered at the connection point. Fig. 6 illustrates the different
definitions of reactive power capability that are found in current grid codes.
Fig. 7 shows the reactive power capability requirement as defined in the European Network
Code shown in GREEN for the stipulated voltage variations on the connection point. The
actual reactive power capability provided by the generator with a step-up transformer is
illustrated based on representative transformer impedance values (0% shown in RED and
17% in MAGENTA). The reactive power capability depends on both the generator and
the step-up transformer design.
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TR-69 — Grid Code Impacts on Generator Standards
Fig. 6. Specification of reactive power capability at the connection point and at the
generator terminals.
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TR-69 — Grid Code Impacts on Generator Standards
Fig. 7. European Network Code reactive power capability requirements versus generator
capability with step-up transformer
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TR-69 — Grid Code Impacts on Generator Standards
Unrealistic grid code requirements such as operating the generator at rated load and 0.85
overexcited power factor when the grid voltage is at its uppermost limit may cause
excessive generator voltages. Similarly, operating the generator at rated load and 0.95
under-excited power factor when the grid voltage is at its lower most limit may lead to
excessive armature currents. In such instances, as shown in Fig. 7, it is not possible to
meet the reactive power requirements with conventionally designed synchronous
machines if no on-load tap changing (OLTC) transformer is used. The alternative is to
use an oversized and more expensive generator for such unlikely operating conditions.
3.1.3 Short-Circuit Ratio (SCR)
IEEE C50.13 [1] and IEC600034-3 [3] specify the value of the short-circuit ratio shall be
not less than 0.35. The SCR (Kc), as defined in IEC600034-4 [4], is determined from the
no-load saturation and three-phase sustained short-circuit characteristics as a quotient of
the excitation current corresponding to the rated voltage on the no-load saturation curve
and the excitation current corresponding to the rated current on the short-circuit curve.
if o
SCR = Kc =
if k
i f o = field current at no-load & rated terminal voltage
i f k = field current at 3-phase short-circuit & rated stator current
Despite the SCR specified in the standards, most generators in the past were designed to
have a SCR > 0.45. However, there is an increasing trend that grid codes are specifying a
value of SCR ≥ 0.5. It is generally believed that a generator with a high SCR will contribute
to improved grid stability. Investigations [11] show that the effect of a ±10% variation of
the SCR on the critical fault clearing time of the generator equipped with a modern, fast,
and high gain excitation system is only marginal. Furthermore, increasing the SCR to
improve grid stability can only be effective for certain grid configuration at the connection
point. (For leading power factor operation and high external reactance.)
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TR-69 — Grid Code Impacts on Generator Standards
Fig. 8. Impact on size due to increase of SCR.
The SCR can be increased by either de-rating a larger unit or by increasing the air gap of
the generator sized for maximum thermal utilization [9], both of which have undesired
consequences.
Consequences of de-rating the unit include:
•
•
Power output reduces with about the same percentage as SCR increases.
For example, when the SCR of 0.45 is increased to 0.5, the MVA rating is
reduced from 1 p.u to 0.9 p.u.
The generator weight increase amounts to about 0.6 times the percentage of the
SCR increase. For example, when the SCR of 0.45 is increased to 0.5, the weight
of the unit will increase from 100% to 107%. This weight increase has a
corresponding cost effect.
Fig. 8 shows visually the size impact of increasing the SCR by de-rating the unit.
12
TR-69 — Grid Code Impacts on Generator Standards
Consequences of increasing the air gap include:
•
The generator weight increase amounts to about 0.35 times the SCR increase
(e.g., SCR: 0.45 → 0.5  Weight [corresponding cost effect]: 100% → 104%);
see Fig. 9
For the same rotor, the rated field current increases with the air gap and leads to higher
temperature and lower efficiency.
Fig. 9. Generator with a standard SCR (left) and an increased SCR (right with an
increased air gap)
3.1.4 Conclusions and Recommendations on Capability Envelope
Machine manufacturers must contend with many design challenges that may not be
economically viable or practical, to fulfill the voltage-frequency operating ranges as
defined in all grid codes. When the requirements in the grid codes are not harmonized, it
is difficult to design standard generators for standard turbines, thus increasing the
engineering as well as manufacturing efforts. These extra efforts translate to increase cost
impact on the generator. Even if the equipment can be manufactured to meet the enlarged
V-f ranges, the outcome of the design will lead to oversized machines. Higher flux density
equates to overheating risks for the generator and possible failure.
Recommended solutions proposed to address design issues or conflicting requirements
stipulated in standards and grid codes on V-f ranges are:
•
Clear definition in grid codes on the operating conditions, expected duration and
frequency of occurrence of voltage-frequency excursions by the transmission system
operators (TSO’s);
•
Standards to accept short-term overheating during short term voltage and frequency
excursions (first discussed in IEC TC2, WG12 the discussions are on-going);
•
Standards to provide guidelines to evaluate life time consumption due to such
excursions (IEC TC2 WG12/IEEE WG C50.13).
13
TR-69 — Grid Code Impacts on Generator Standards
•
Consideration of extending the voltage variation allowed by equipment standards
from ±5% to ±7.5%, as is often required to comply with current grid codes.
Unrealistic grid code requirements as operating the generator at rated load and 0.85
overexcited power factor when the grid voltage is at its uppermost limit may cause
excessive generator voltages. Similarly, operating the generator at rated load and 0.95
under-excited power factor when the grid voltage is at its lower most limit may lead to
excessive armature currents. In such instances, it is not possible to meet the reactive power
requirements with conventionally designed synchronous machines, if no OLTC
transformer is used. The alternative is to use an oversized and more expensive generator
for such unlikely operating conditions.
Possible solutions to resolve conflicting reactive power capability requirements in
standards and grid codes as well as to ensure appropriately generator designs are as follows:
•
Grid codes to also define requirements at the generator terminals and to harmonize
V-f ranges as much as practical.
•
TSO’s to allow OLTC generator transformers in all transmission grids when the
voltage variations at the connection point results in voltage variation at the generator
terminals that exceeds those stipulated in the standards for all required reactive power
operating conditions.
•
TSO’s to issue realistic operating guidelines with regards to maximum lagging
power factor during high system voltages and maximum leading power factor during low
system voltages.
Generators can increase its SCR value by either de-rating a larger unit or by increasing its
air gap of the generator sized for maximum thermal utilization, both of which have
undesired consequences.
It is the opinion of this task force, that the impact of grid code SCR requirements on
generator design can be minimized by:
•
Harmonization of grid code requirements for countries with similar grid topology
(e.g. harmonizing the requirements for SCR, reactive power capability and V/f operating
range).
•
Reduction of SCR requirements in grid codes for large generating units e.g. in the
UK, for generators rated greater than 1600 MVA, the SCR should not be less than 0.4.
•
TSO’s to work with IEC/IEEE to harmonize SCR requirements both in grid codes
and in the standards.
•
Grid codes to have the flexibility of allowing for a lower generator SCR if studies
show no significant benefit in terms of grid stability with a unit having a higher SCR.
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TR-69 — Grid Code Impacts on Generator Standards
3.2
System Fault Related Requirements
This section discusses system faults that have an impact on the generator’s and power
plant’s response.
3.2.1 Impacts of System Faults on Generators and Power Plant Response
System faults can affect synchronous generators in different ways: loss of synchronism,
power plant auxiliaries tripping, or induced high electromechanical stresses.
An important aspect of fault ride‐through studies is determining the critical fault clearing
time. This means considering the possibility that by the time that the fault has cleared, the
rotor could have accelerated such that synchronism with the power system is lost. If loss
of synchronism occurs, the generator must be disconnected from the grid to avoid machine
damage. Loss of synchronism can be detected by out-of-step and over-frequency
protection.
Power plant auxiliaries can trip on low AC voltage, AC voltage contactor dropout, and
stalling of induction motors loads that drive power plant auxiliary equipment (typically
pumps, compressors, fans, etc.). Motor stalling is detected by bus under-voltage protections
and motor over-current protections.
High electromechanical stresses can be caused by system short-circuits accompanied by
switching operation of a transmission line to remove the fault. Such line auto re-closing
operation can induce torques on the shaft of the machine that are even higher than stresses
caused by three phase short-circuits or out of phase synchronization and hence poses a
safety issue if the shaft is damaged.
Grid Code requirements on the ability of the generator to withstand system faults is defined
in different ways. The European and the North American grid code are discussed with
regards to fault ride through capability because they consider different formulations of the
requirement.
3.2.2 Single Fault Ride Through Capability
Generators designed to IEEE C50.13 or IEC 60034 standards to withstand sudden shortcircuits do not automatically comply with the grid code fault-ride-through requirements
[9].
In the European Union Network Code (EU NC, developed by ENTSO-E) [10], fault ride
through means the capability of a generator to be able to remain connected to the network
and operate through periods of low voltage at the connection point caused by secured
(bolted) faults. A voltage-against-time profile describes the conditions in which the
generator is capable of staying connected to the network. In Fig. 10, the horizontal axis is
chronological time of the specified fault event. Each Transmission System Operator (TSO)
in the EU can specify a curve between the defined limits. No tripping (including loss of
synchronism) is permitted for a voltage profile occurring at or above the specified curve.
A transient voltage variation over a polygonal time-voltage curve may occur if a fault
15
TR-69 — Grid Code Impacts on Generator Standards
occurs at the generator HV bus, if the generator is connected to an infinite grid through the
step-up transformer and a transmission line (external reactance) as shown in Fig. 11. The
transient variation of the HV bus can be separated into two periods. The first period
corresponds to the fault period: and an abrupt voltage change due to the fault, and the
second period corresponds to the post-fault period. The transient variation of the HV bus
voltage is determined by the generator transient response and the generator connecting
impedance (sum of the step-up transformer and transmission line impedances).
In North America NERC Reliability Standard PRC-024-2 [19] (developed by NERC),
defines how voltage and frequency protective relays must be set to withstand specified
voltage-against-time duration curves. Each Generator Owner that has generator voltage
protective relaying activated to trip its applicable generating unit(s) shall set its protective
relaying such that the voltage protective relaying does not trip because of a voltage
excursion (at the point of interconnection) caused by an event on the transmission system
external to the generating plant. In Fig. 12, the horizontal axis is required time duration for
a specified voltage. It is applied to both “over” and “under” voltage protective relaying. It
must be emphasized that no generator stability requirement is imposed by NERC PRC024-2.
Fig. 10. EU NC fault ride through capability.
16
TR-69 — Grid Code Impacts on Generator Standards
Generator
Connection point
Grid

SG
Fault
V
t
Fig. 11. EU NC: Physical interpretation of fault ride through capability.
(Note: in Fig. 11 the fault shown is located in the grid relatively close to the power plant.)
Fig. 12. NERC low and high voltage ride through capability.
Consider a simulation model of a generator connected to the infinite grid through a stepup transformer and external reactance between the step-up transformer and the infinite grid
from Fig. 11. A bus-fed static excitation system supplies the generator excitation. The
excitation system incorporates a speed deviation power system stabilizer. A key parameter
that affects synchronous machine transient stability is rotor inertia: higher rotor inertia
results in the ability to withstand longer faults. The inertia constant of the selected generator
(6.5 s) is in the upper range of synchronous generator inertia. The active power supplied
by the generator is 0.85 pu on the machine MVA base, whereas the reactive power
consumed by the generator depends on the reactive power requirements imposed by each
grid code. The extreme leading operating point has been chosen as the most demanding
operating point. As a short circuit capacity is not specified by the EU Network Code, this
study has assumed that it is 20 times the generator MVA base (which corresponds to a line
reactance equal to 0.05 pu).
Fig. 13 shows the voltage variation at the connection point and the generator terminals
compared to EU NC requirement in the case of lowest available choice of maximum fault
17
TR-69 — Grid Code Impacts on Generator Standards
duration (140 ms). The generator is stable and the voltage at the connection point is over
the required voltage. Fig. 14 shows the voltage variation at the connection point and the
generator terminals compared to EU NC requirement in the case of maximum fault duration
(250 ms). The generator is unstable in this case. Generator terminal voltage shows
generator instability due to the loss of synchronism more clearly than connection point
voltage.
Fig. 13. Generator response in the event of 140 ms three-phase fault: voltage variation at
the connection point and at generator terminals compared to EU NC requirement.
Fig. 14. Generator response in the event of 250 ms three-phase fault: voltage variation at
the connection point and at generator terminals compared to EU NC requirement
The sensitivity of the critical clearing time (maximum fault duration) with respect to the
operating point and the impedance of the transmission line (external impedance) is
investigated. Fig. 15 shows the variation of the critical clearing time when external
18
TR-69 — Grid Code Impacts on Generator Standards
impedance varies from 0.05 pu to 0.5 pu in cases of extreme leading, unity and extreme
lagging power factor operating points of the EU NC reactive power requirements.
In the case of the extreme lagging operating point, the selected generator would fulfill the
EU NC maximum fault duration requirement even if the external reactance was high (0.25
pu). However, in the case of the extreme leading operating point and for a low external
reactance (0.05 pu), the critical clearing time is 200 ms, which is between the minimum
fault duration (140 ms) and the maximum fault duration (250 ms). The response of a
generator also depends on several parameters: rotor inertia (H), short circuit ratio (SCR),
and excitation system ceiling factor (CF).
Fig. 16 shows the variation of critical clearing time when external reactance varies from
0.05 pu to 0.5 pu in the case of the extreme leading operating point of the EU NC reactive
power requirement when the generator inertia constant takes four different values (3.5, 5,
6.5 and 8 s), which covers a wide range of technologies. The rotor inertia constant of the
typical generator was 6.5 s. Rotor inertia depends on the prime mover type (hydro, steam,
gas or Combined Cycle Gas Turbine). Even a generator driven by a single shaft CCGT
whose inertia constant is very high (8 s) does not satisfy the EU NC most demanding
requirement (250 ms), combined with extreme and unlikely national choice of initial study
conditions. Lower rotor inertia results in lower critical clearing time. If rotor inertia
constant is 3.5 s, the critical clearing in the case of a 0.05 pu external reactance is 150 ms.
SCR is a key parameter of synchronous machine design. Fig. 17 shows the variation of
critical clearing time when external impedance varies from 0.05 pu to 0.5 pu in the case of
the extreme leading operating point of the EU NC reactive power requirement for three
values of SCR. The SCR of the typical generator used in this study was 0.63 pu. The effect
of ±10% variation of the SCR on critical clearing time is small.
On the other hand, ceiling factor (CF) is a key parameter of excitation system design. Fig.
18 shows the variation of critical clearing time when external impedance varies from 0.05
pu to 0.5 pu in the case of the extreme leading operating point of the EU NC reactive power
requirement for three values of CF. The base CF of the generator used in the investigation
was 3 pu. The effect of ±20% variation of CF on the critical clearing time is very small.
This is due to the fact that the field voltage during the fault period is mostly determined by
the terminal voltage instead of by CF since the generator is equipped with a bus fed static
excitation system.
19
TR-69 — Grid Code Impacts on Generator Standards
400
Extreme Lagging
Unity
Extreme Leading
Critical Clearing Time (ms)
350
300
250
200
150
100
50
0.05
0.1
0.15
0.2
0.25
0.3
0.35
External Reactance (pu)
0.4
0.45
0.5
Fig. 15. Sensitivity of critical clearing time with respect to generator power factor.
400
H
H
H
H
Critical Clearing Time (ms)
350
=
=
=
=
3.5
5.0
6.5
8.0
s
s
s
s
300
250
200
150
100
50
0.05
0.1
0.15
0.2
0.25
0.3
0.35
External Reactance (pu)
0.4
0.45
0.5
Fig. 16. Sensitivity of critical clearing time with respect to generator inertia.
400
SCR=0.69
SCR=0.63
SCR=0.57
Critical Clearing Time (ms)
350
300
250
200
150
100
50
0.05
0.1
0.15
0.2
0.25
0.3
0.35
External Reactance (pu)
0.4
0.45
0.5
Fig. 17. Sensitivity of critical clearing time with respect to generator SCR.
20
TR-69 — Grid Code Impacts on Generator Standards
400
CF=2.4
CF=3
CF=3.6
Critical Clearing Time (ms)
350
300
250
200
150
100
50
0.05
0.1
0.15
0.2
0.25
0.3
0.35
External Reactance (pu)
0.4
0.45
0.5
Fig. 18. Sensitivity critical clearing time with respect to generator ceiling factor.
A high excitation voltage CF may impose additional duty on the generator rotor winding
insulation system. Rotor insulation systems are crucial to the reliability of a generator. For
large generators, a high excitation voltage CF may mean exceeding the insulation design
voltage limits. Fig. 19 depicts the excitation field voltage acting on the rotor circuit causing
stress on the rotor insulation in the rotor slot. The field winding will be exposed to full AC
voltage levels with switching spikes (see Fig. 20) that reach the field ceiling voltage several
times per cycle. For a unit with high voltage CF, these spikes may exceed the allowable
voltage level of the rotor winding insulation.
Fig. 19. Excitation voltage acting on rotor circuit
21
TR-69 — Grid Code Impacts on Generator Standards
Fig. 20. Measured waveforms of the DC output voltage of the excitation unit and
corresponding AC input voltage.
3.2.3 Multiple Fault Ride Through Capability
As a result of some recent major power system disturbances, some grid operators have
drafted new grid code requirements [14], [16] stipulating compliance to multiple fault ride
through events. As already mentioned in Section 3.2.2, generators designed to IEEE
C50.13 or IEC 60034 standards to withstand sudden short-circuits do not automatically
comply with the single fault-ride-through requirements. With multiple fault ride-through,
the impact of such events is in general even more severe on the generators.
In Germany [15], for multiple fault ride through capability, the synchronous power
generation unit (Type 1) must be capable of remaining connected to the power system
under the pre-fault conditions shown in Table 1 and the voltage disturbance profile at the
connection point as shown in Fig. 21.
Table 1. Boundary Conditions for Multiple Fault Ride Through Capability Validation.
Fault Type
LVRT, 3-phase
Remaining
residual voltage
relative to the
rated voltage of
the grid
0.3 then 0.3
Pre-fault voltage
at the connection
point relative to
the rated voltage
of the grid
1.0
22
PGU
pre-fault
active power
PGU
pre-fault
power factor
1.0
1.0
TR-69 — Grid Code Impacts on Generator Standards
Fig. 21. RMS connection point voltages over time for multiple faults.
In the Australian National Electricity Rules (NER) [16], the Minimum Access Standard for
multiple voltage disturbance ride-through capability requires a synchronous generating
system and each of its generating units to remain in continuous uninterrupted operation for
a series of up to 6 disturbances within any five-minute period caused by any combination
of events. Reference [17] provides the results of a simulation carried out to show
compliance. Assessment criteria are:
a) An accumulated disturbance duration (Δt).
b) A total number of disturbances within pre-defined sliding time windows.
c) Sum of changes in voltage by the duration of the disturbance (ΔV x Δt).
An example taken from [17] of the multiple disturbance sequence and the connection point
voltage profile is shown in Fig 22. It shows a combination of multiple 2 phase faults
including a circuit breaker failure followed by unsuccessful single-phase line autoreclosing.
23
TR-69 — Grid Code Impacts on Generator Standards
Fig 22 RMS connection point voltages over time for multiple faults.
The above examples of multiple fault ride-through capability requirements clearly indicate
that gaps between grid code requirements and standards are increasing without
understanding the consequences or the impact on synchronous generator design. It is also
unclear for the case of the Australian NER rule changes, what type of disturbances must
be investigated to ensure a generating unit can meet the requirements. To withstand such
multiple fault events, project specific design studies must be carried out on the generating
plant including interconnected adjacent substations and generating plants. Whether it is
within the scope of equipment design standards to recommend design measures to ensure
multiple fault ride-through withstand capability, is an issue that needs to be agreed within
the standards and grid code communities.
Challenges from the generator OEM point of view are:
•
•
•
•
The mechanical integrity of the shaft-line as a consequence of multiple
disturbances. No standard generator design can be proposed without a detailed
investigation as the risks of structural damage cannot be quantified otherwise;
The electrical stresses on the generator windings;
How to monitor these fault events and to account for life-time impact;
It is necessary to check for each power plant configuration, the impact of multiple
disturbances on all aspects of equipment design (mechanical, electrical,
economical) on a project specific application;
24
TR-69 — Grid Code Impacts on Generator Standards
3.2.4 Rate of Change of Frequency (RoCoF)
The synchronous machine standards of IEEE C50.13 and IEC60034 do not specify any
requirement for RoCoF withstand capability. Existing and new synchronous generator are
not specifically designed to meet any RoCoF withstand capability requirements.
However, with the increasing integration of non-synchronous generation into the electrical
supply system, RoCoF withstand capability requirements are now appearing in many grid
codes. As with previously discussed grid code requirements, the one related to RoCoF
withstand capability is also not harmonized amongst the various national grid codes. Grid
codes typically require generators to stay connected during high gradients of grid
frequency, termed Rate of Change of Frequency (RoCoF) events. Usually only the
maximum gradients (e.g. 1 Hz/s) are defined, but the boundary conditions (such as duration
and frequency profile) in most cases stay unclear and do not allow a detailed evaluation
from a generator capability point of view. In some extreme case, such as in the Australian
grid code, the generator is required to withstand a RoCoF of up to 4Hz/s for 0.25s. Since
standards do not currently provide any guidance on RoCoF withstand capability, the only
way to determine such capabilities would be for the generator OEM to carry out a detailed
analytical assessment of the unit for a specific site. Such assessments are very time
intensive covering electrical, mechanical, protection as well as control aspects of the unit
and other affected equipment in the power plant. Several OEMs are currently carrying out
such studies for existing power plants in Ireland [18] to determine RoCoF withstand
capability. The investigations carried out have provided further insight on how grid codes
could better define the RoCoF withstand requirements.
As a minimum, grid code requirements related to RoCoF need to define:
•
•
Expected duration of the RoCoF and
Measurement conditions for the RoCoF as the sample time will determine the
RoCoF magnitude (see Fig. 23).
Fig. 23. RoCof as a function of measurement duration.
25
TR-69 — Grid Code Impacts on Generator Standards
A more useful definition would be to provide a representative set of frequency traces
[18], one of which is shown in Fig. 24.
Fig. 24. 1 Hz/s frequency drop with subsequent fast recovery resulting in over-frequency
representative trace
A subject study [7] provided analyses of RoCoF impact on generator dynamic behavior.
Frequency changes with a constant gradient will result in an immediate active power step
request at the generator terminal. Table 2 shows an example of a gas turbine driven
generator responding with active power steps for different RoCoF values. The power step
can represent either the deceleration or acceleration power for the entire turbine-generator
shaft line. For instance, a frequency gradient of 1.0 Hz/s may mean a power step at the
generator terminals of 35%.
Table 2. RoCoF and the Corresponding Impact on Power Step
Fig. 25 shows the power step for a negative frequency gradient RoCoF event. A negative
RoCoF results in an increase of exported power and consequently an increase of generator
load angle. A new power balance may occur or if the load angle exceeds its stability limits
26
TR-69 — Grid Code Impacts on Generator Standards
for a certain duration this may lead to generator pole slip and a loss of synchronism with
the grid. The consequence of pole slipping is that severe duty will be placed on the unit
(large stator currents, high mechanical stresses, high induced voltages and currents in the
rotor).
Fig. 25. A negative frequency gradient RoCoF event and the resulting Delta-power step
change.
The study [7] also investigated the impact of increasing the automatic voltage regulator’s
ceiling voltage. It was found that such a solution has only limited effect on RoCoF
withstand capability. It was further determined that increasing voltage ceiling factors in the
range of 2.5 to.3.0 resulted in no significant increase of the maximum RoCoF withstand
capability. Fig. 26 depicts this latter analysis for both frequency decrease and frequency
increase
RoCoF
events.
Fig. 26. RoCoF withstand as a function of AVR ceiling voltage.
27
TR-69 — Grid Code Impacts on Generator Standards
3.2.5 Auto Re-Closing
On the topic of line auto re-closing and the impact on synchronous machines, IEC 60034
[2][3] standards do not provide any requirements or guidance. IEEE C50.13 recommends
explicit system studies for generators that are anticipated to experience duty from rapid
reclosing [1].
In IEEE C50.13, it is stated:
•
•
•
Rapid reclosure (successful & unsuccessful) results in shaft torques which are
statistical in nature and could lead to cumulative fatigue damage to shafts;
Generalized torsional stress requirements to design the equipment are not possible;
Unit-specific study is recommended to be performed.
In addition to faster higher-ceiling excitation systems, high-speed reclosing of generation
lines could also improve the critical clearing times and therefore increase the fault-ridethrough / stability margins. In European grids [10], generating units shall be capable of
remaining connected to the network during single-phase or three- phase auto-reclosures.
Fig. 27 shows a typical grid configuration with auto-reclosing on the transmission lines.
Fig. 27. Grid with typical auto re-closing transmission lines.
The major effects of auto-reclosing on generators are high mechanical torques in the shafts
and high forces on generator end-windings. The impact of reclosing conditions and specific
networks on existing generators depends on many different factors (e.g. shaft inertia,
28
TR-69 — Grid Code Impacts on Generator Standards
stiffness, cross-section) and should be the scope of a unit-specific study. Fig. 28 shows the
generator’s air gap torques during a short circuit and the subsequent line auto-reclosing
sequence. Fig. 29 shows the rotor dynamic assessment on the shaft line to determine the
mechanical stresses against design limits.
Fig. 28. Short-circuit and reclosing sequence.
Fig. 29. Rotor dynamic assessment of stresses due to auto-reclosing.
Beginning in the mid-1970’s simulations of the effect of reclosing were made using
detailed modeling of generator electrical torques (Park’s equations) and the mechanical
behavior of the shaft including the elastic limits of the metal [[52] - [56]. These studies
29
TR-69 — Grid Code Impacts on Generator Standards
showed that the shaft mechanical damping was limited and that the torque transient
created by three phase reclosing could cause excessive loss of shaft life. Because of this
risk, the conclusion was reached that three phase reclosing was a hazardous practice. In
the light of these findings, three phase reclosing should only be attempted after careful
and detailed study to preclude the possibility of causing severe machine damage.
The torques associated with single phase reclosing are less severe, but there are other
problems that need to be addressed, such as guaranteeing the extinction of the secondary
arc that is energized by capacitive coupling to the healthy phases.
3.2.6 Maximum Power Output vs. Frequency
As already discussed in Section 3.1, the IEEE C50.13 [1] and the IEC 60034 [2][3]
standards specify that generators shall be capable of continuous operation over the
frequency range of ±2%. For the frequency range of +3% to –5%, operation should be
limited in extent, duration, and frequency.
In many grid codes, there is a requirement to provide maximum active power output during
under frequency conditions. The European grid code [10], specifies that power-generating
modules shall be capable of maintaining constant power output at its target active power
value regardless of changes in frequency. Furthermore, the relevant TSO shall specify
admissible active power reduction from maximum output with falling frequency within the
boundaries of the solid line as shown in Fig. 30. The admissible active power reduction
shall be:
•
•
Below 49 Hz falling by a reduction rate of 2% of the Maximum Capacity at 50 Hz
per 1 Hz Frequency drop;
Below 49.5 Hz by a reduction rate of 10% of the Maximum Capacity at 50 Hz per
1 Hz Frequency drop.
The UK and Poland grid code requirements are shown by dotted BLUE lines.
30
TR-69 — Grid Code Impacts on Generator Standards
Fig. 30. Maximum power capability reduction with falling frequency.
Such requirements are not consistent with the continuous frequency operating range
defined in the standards. This requirement is primarily focused on technologies not able to
provide full active power during under frequency such as gas turbine powered power
plants. The objective is to limit the potential reduction of active power generation after the
disturbances in the system and therefore avoiding more severe disturbances, (i.e.,
frequency collapse in a synchronous area possibly leading to cascade tripping, system
splitting, load shedding, and even total blackout).
For gas-fired power plants, the physical behavior of a gas turbine results in a significant
decrease of gas turbine output with frequency drop when the ambient temperature is high.
See Fig. 31. The upper boundary of the EU requirements is shown by the RED curve. In
the UK grid code, there is a limitation of the requirement to 25°C ambient temperature. In
other grid codes where there is no temperature limitation specified, it is unclear whether
the requirements can be met. In any case, to meet this requirement, the gas turbine must be
over-fired causing additional equivalent operating hours (EOH) of the unit.
31
TR-69 — Grid Code Impacts on Generator Standards
Fig. 31. Typical GT output as a function of frequency and ambient temperature.
32
TR-69 — Grid Code Impacts on Generator Standards
The consequence of such requirements on gas-fired power plants are as follows:
(data from according the European Association of Gas and Steam Turbine Manufacturers
[63])
•
•
•
•
•
The need to “de-rate” units to provide headroom for a possibly never occurring
event.
Higher capital costs for dead capacity and loss of optimal efficiency. The total
economic impact (for the European market) is estimated at 0.5 B€.
The need to develop and install compensation mechanisms with inherent activation
delay times, leading to an estimated economic impact of 0.1 B€.
Risk to system stability. System may fully collapse if those compensation
mechanisms fail and hence also a risk of black out. The latter risk may be in the
order of several B€.
The imposition of requirements for maintaining unit output during underfrequency
conditions does not eliminate the need for underfrequency load shedding, such as
was implemented in North America after 1965.
3.2.7 Conclusions and Recommendations on Fault Related Issues
Generators designed to IEEE C50.13 [1] or IEC 60034 [2][3] standards to withstand sudden
short-circuits do not automatically comply with the fault-ride-through requirements. It
would be helpful if the standards provide design guidelines related to fulfilling single FRT
requirements.
Investigations carried out have shown that FRT withstand capability depends not only on
generator characteristics but also on external factors such as:
•
•
•
System pre- and post-fault conditions
Generator transformer reactance
System strength at connection point
Therefore, grid codes should provide also such information to ensure proper investigations
can be carried out for the design of the power plant.
FRT requirements may also impact generator design parameters such as inertia, SCR,
voltage ceiling factors, frame size etc. A standard generator design is nearly impossible to
achieve which can comply with the diverse voltage-time curves that are specified in the
grid codes.
Using an excitation with a higher pulse (e.g. 12 pulse or more) thyristor converter for large
generators may reduce the DC over voltages to acceptable levels for units with a high
excitation voltage CF. The disadvantages of this approach are:
•
•
•
•
Increased equipment costs
Non-industry standard solution
May require new development of converter bridges for large units
New development is not field proven
33
TR-69 — Grid Code Impacts on Generator Standards
Alternative solutions to high excitation voltage CF:
•
•
Replacing a potential sourced excitation system with a separately sourced system.
This, however, will lead to additional components (transformers, circuit breakers,
bus connection, etc.) and increased equipment costs. Also, the separate source
should not experience significant voltage dip during the fault.
Other means of improving FRT capability such as fast-valving for steam turbines
or boosting field voltage during fault events. Similarly, these alternatives result in
increased equipment costs and more complex control systems.
As such, FRT withstand capability is a system issue and not just a generator equipment
issue. Solutions to meeting diverse and extreme FRT requirements must therefore also
consider optimizing performance of all affected power plant equipment as well as the grid
system parameters and operational procedures.
On the issue of multiple fault ride-through capability, many of the conclusions and
recommendations discussed for single FRT capability are also valid for the multiple FRT
capability. Since the latter requirements are relative new and place additional severe duty
cycles on the generator, it is difficult to ascertain the impact and risks on generator design.
It also appears multiple fault events are non-exhaustive and site specific so the probability
of not being able to capture a worst-case event sequence can be high.
In the opinion of this task force, only detailed electro-mechanical investigations on a
project specific plant design can determine the impact of multiple fault-ride through events
on the mechanical and electrical design of the generator. These analyses have to be carried
out including the impact of adjacent power system, resulting in a significant effort to carry
out such investigations.
The RoCoF investigations carried out by OEMs, have provided further insight on how grid
codes could better define the RoCoF withstand capability requirements.
As a minimum grid codes should define:
•
•
•
Expected duration of the RoCoF
Measurement conditions for the RoCoF, as the sample time will determine the
RoCoF magnitude
A representative set of frequency traces of RoCoF events.
Currently the only way an OEM can reliably determine high RoCoF withstand
requirements is to carry out a detailed investigation. It is also equally important that
equipment standards should also consider such requirements to provide design criteria
guidance to OEM and customers for specifying the appropriate RoCoF withstand
capability.
With regards to line auto re-closing, IEEE C50.13 [1] recommends that a unit-specific
study should to be performed to determine any impact of auto re-closing on the generator.
IEC 60034 [3] has currently no guidelines related to auto re-closing.
34
TR-69 — Grid Code Impacts on Generator Standards
Grid operators should understand the consequence and impact of auto re-closing on the
generator turbine shaft-line. If stresses during auto re-closing are too high, there is risk of
catastrophic mechanical damage to the unit. To allow for unit-specific study, grid operators
should provide all the relevant inputs for carrying out such studies or should undertake this
responsibility themselves.
Due to the statistical character of re-closing events, the “worst” case may not be known nor
covered by design. To reduce the risk of high mechanical stresses on the generating unit,
it is recommended that line auto re-closing schemes should include supervision by synchrocheck relays to avoid re-closing onto a fault. Machine shaft integrity shall be considered
the top priority to ensure grid reliability and availability.
On the issue of maximum power capability reduction with falling frequency, IEEE C50.13
[1] and the IEC 60034 [2][3] standards specify that generators shall be capable of
continuous operation over the frequency range of ±2%. For the frequency range of +3%/–
5%, operation should be limited in extent, duration and frequency. It should be noted that
some prime movers, such as steam turbines have resonance points that can result in rapid,
cumulative damage that may require their immediate tripping.
Many grid codes require that the power-generating module shall be capable to maintain
constant output at its target active power value regardless of changes in frequency.
The consequence of such requirements on gas-fired power plants are:
•
•
•
•
The need to “de-rate” units to provide headroom for an event which may never
occur.
Higher cost /kW Capex for dead capacity, losing best efficiency, with cost
impacts measured in the hundreds of millions of Euros (dollars).
The need to develop and install compensation mechanisms with inherent
activation delay times, again with cost impacts measured in the hundreds of
millions of Euros.
Risk on system stability. System may fully collapse if those compensation
mechanisms fail and hence also a risk of black out. The latter risk may be in the
order of several billion Euros.
Grid codes should in future also include the duration and ambient temperature conditions
for this requirement.
An alternative solution would be to replace the requirement by intrinsic gas turbine
behavior only (manufacturers to provide the unit specific maximum power versus
frequency curves). Additionally, the load shedding schemes should be adjusted through
simulations.
The installation of storage devices (e.g. battery energy storage system), with a capacity
ranging between 1 and 5 % of the rated power of the plant (e.g. 1 MVA for a 100 MVA
power plant) could increase its flexibility. Those devices may also provide ancillary
services to the grid.
35
TR-69 — Grid Code Impacts on Generator Standards
3.3
Generator Excitation Systems
3.3.1 Introduction
Grid codes are typically written as a result of system-wide stability and reliability studies,
and the associated excitation system requirements are related to equipment and information
which can be the responsibility of many varied stakeholders. Considerations for excitation
related requirements can include the following:
•
•
•
Power system stability
Excitation limiter coordination with power equipment capabilities and protective
relays
Turbine/rotor shaft torsional oscillations
Historically power utilities were vertically integrated and often state regulated, with
individuals or departments tasked with performing studies, writing specifications,
evaluating bids, purchasing equipment, overseeing construction and commissioning and
conducting performance testing. Finally, operating guidelines would be written to deal
with out of service equipment in the plant or transmission system and other contingencies.
Most jurisdictions no longer operate the power system in this way but have transitioned to
deregulation of the power system and operation under a rule-based market system instead
of a monopoly electricity provider.
As a result, it is necessary to study the grid code requirements carefully and consider inputs
from various stakeholders in addition to selecting appropriate excitation equipment. In the
authors’ experience, it is often the excitation vendors who are tasked implicitly or explicitly
with a diverse set of requirements including not only the excitation system itself, but the
generator, turbine, protective relays and operating rules. Excitation vendors cannot satisfy
all applicable grid code requirements in isolation and require collaboration and assistance
of all stakeholders.
In the following subsections, this report will separately elaborate on power equipment
design and functional design aspects of excitation systems relating to grid codes and to the
applicability and acceptance procedure requirements of various grid codes relating to
excitation systems.
3.3.2 Excitation System Power Equipment Design
a) Power Equipment: Static versus Rotating Exciters
The choice of a power source for excitation of synchronous generators has been well
documented over the years but is briefly introduced again here for convenience. Excitation
current for very large synchronous generators is typically introduced to the main field or
rotor winding through stationary carbon brush gear in contact with rotor mounted collector
rings also known as slip rings as shown in Fig. 32.
36
TR-69 — Grid Code Impacts on Generator Standards
Fig. 32 Brushgear & slip rings for static excitation
Known as a static excitation system, this arrangement, as shown in Fig. 33, is typically
supplied, often indirectly, from the same power system to which the generator delivers
power.
Fig. 33 Simplified schematic representation of static excitation system
Static excitation systems provide direct, and therefore fast, control of the voltage applied
to the generator rotor. As an alternative to static excitation, many generators are delivered
with brushless excitation systems where a smaller synchronous generator (a rotating
exciter) is integrated on the same shaft train as the main generator together with a rotating
rectifier so that excitation current is delivered to the main generator field without the need
for brush gear as shown in Fig. 34 and Fig. 35 below.
Fig. 34: Simplified schematic representation of a brushless excitation system.
37
TR-69 — Grid Code Impacts on Generator Standards
Fig. 35: Example of a rotating exciter and rectifier.
Other variants of excitation power supply are also used. For example, static excitation
systems exist with compounding current transformers. This enables continuation of
excitation supply while a power system short circuit fault is present. Also, some systems
exist where the power source is a small generator on the same shaft as the main machine
but the control system feeds the power to the rotor via brush gear. IEEE Std. 421.5 [57]
provides a more thorough introduction to available types of excitation system.
In developing grid codes reference is typically made to power system stability studies using
dynamic models of the generators and their excitation and governor controls. This has led
to some grid codes specifying speed-of-response requirements which can be difficult to
meet without direct electronic control of the voltage applied to the main generator field.
Hence, grid codes can sometimes dictate the use of static excitation without explicitly
prohibiting rotating exciters. The UK grid code, for example, specifies a range of speed of
responses which are tailored by project related studies to meet the needs of the grid network
and the proposed grid connection point so that a brushless generator may be used unless
the study results indicate that a static excitation system is necessary.
Grid codes typically have stability-based rules which have implications both on the
hardware and the selection of tunable settings. Vendors typically take responsibility for
hardware and protection settings and frequently other stakeholders are responsible for
system tuning depending upon a thorough understanding of local stability rules and
Transmission System Operator preferences.
Some grid codes specify that the excitation system must be able to provide a defined
negative main generator field voltage which is generally not possible using a brushless
excitation system equipped with a rotating diode rectifier. This report suggests that when
opportunities for review of such grid codes occur, flexibility should be introduced. This
will avoid unnecessarily restricting the available options for areas of the power system
where brushless excitation systems could provide satisfactory performance.
Legacy systems with rotating dc or ac exciters may be permitted based on “grandfathering”
but if the excitation system is changed because of end of life or failure, the new system will
usually have to meet the present Grid Code rules.
38
TR-69 — Grid Code Impacts on Generator Standards
b) Power Equipment: Ceilings, Response Time & High Initial Response
Some grid codes require excitation systems classified as High Initial Response (HIR)
which specifies a particular level of fast response time as defined in IEEE Std. 421.1 [58]
and IEEE Std. 421.2 [59].
Others grid codes specify a range of response times. In some cases, specific ceiling values
are determined on a per project basis based on stability studies.
Grid codes generally use terminology that has been defined in IEEE Std. 421.1 [58] when
specifying excitation speed of response times and important notes are included in IEEE
Std. 421.2 [59]. For convenience the key terms are summarized here:
•
•
•
•
Ceiling voltage: “The maximum direct voltage that the excitation system is
designed to supply from its terminals under defined conditions. Note: The ceiling
voltage under load is determined with the excitation system supplying
synchronous machine rated field current.”
Excitation system voltage response time: “The time in seconds for the excitation
voltage to attain 95% of the difference between ceiling voltage and rated field
voltage under specified conditions.”
High Initial response (HIR): “An excitation system capable of attaining 95% of
the difference between ceiling voltage & rated load field voltage in 0.1seconds or
less under specified conditions.”
Specified Conditions: Described in IEEE Standard 421.2: “To permit maximum
flexibility in the design, manufacture, and application of excitation systems, some
of the performance criteria are defined under “specified conditions”. The
applicable conditions are specified by equipment purchaser to meet applicable
reliability or interconnection requirements. Care must be exercised that the “under
specified conditions” clauses are written and interpreted in a manner consistent
with the application.”
Excitation speed of response requirements are frequently more challenging than HIR
requirements, with required response times sometimes being as low as 33ms. (i.e. 3 times
faster than HIR).
Requirements that include a short response time, or HIR, can present challenges for
equipment purchasers and manufacturers who need to select equipment components and
compare the costs of alternative systems. As such, it is very important to identify the
requirements for HIR systems in detail early in an excitation project, before the design is
finalized.
The complete generator and excitation system package should be considered to ensure that
the essential technical requirements for the application can be achieved with the most costeffective product configuration.
It is also important to consider that simply installing a fast response or HIR system can
have negative consequences.
39
TR-69 — Grid Code Impacts on Generator Standards
For example, HIR requirements imply fast responses of a voltage regulator to changes in
the actual value of terminal voltage to benefit transient stability issues of the power system.
But the high dynamic response of the excitation system might unintentionally excite
turbine-rotor torsional oscillation modes as shown on Fig. 36. It may be necessary to
attempt to implement countermeasures to ensure that the frequency range of torsional
oscillations are not excited. It should be recognized that when countermeasures are not
effective it may not be possible to achieve the specified response. Similar interactions may
also occur with reciprocating engine prime movers with fast response excitation.
It is also well known that while a fast dynamic response of the voltage control loop has
transient stability benefits, it can also have a destabilizing impact to the local mode of the
generator. As a result, the requirement of an HIR excitation system usually implies
application of a Power System Stabilizer (PSS), even if not explicitly mentioned in the grid
code.
It is important to note that there is an inconsistency in the definition of ceiling voltage used
by grid codes, which refers to ceiling voltage in terms of rated operating conditions,
whereas simulation modelling standards such as IEEE Std 421.5 and most power system
simulation programs define one per unit generator field current as “that current required to
produce rated synchronous machine terminal voltage on the air-gap line” and one pu field
voltage as “the corresponding field voltage.” As a result, for the same ceiling requirement,
the numerical value of ceiling for voltage and current will be different for the simulation
and the machine rating specified by the grid code.
40
TR-69 — Grid Code Impacts on Generator Standards
Field V
(pu)
1.2
0.8
0.4
0
-0.4
Speed
(pu)
1.0005
1.0000
0.9995
PSS Output
(pu)
Active P
(pu)
0.9990
0.56
0.55
0.54
0.53
0.52
0.51
0.02
0.01
0
-0.01
-0.02
0
2
4
6
8
Time (seconds)
Fig. 36: Excitation of turbine-rotor torsional modes
As the definition of an HIR system states that it is “the time in seconds for the excitation
voltage to attain 95% of the difference between ceiling voltage and rated field voltage under
specified condition” it is necessary to know the rated field voltage. To know the rated field
voltage, both the rated field current and the applicable field temperature for field resistance
calculation must also be known. These values will be known by the generator designer.
The ceiling voltage must also be known and this will need to be specified as a requirement
somewhere, typically as a per unit or percentage value, in a grid code. If the ceiling voltage
is not specified, then it is necessary to assume a value of ceiling voltage when determining
whether a generator complies with HIR requirements. It is possible to state that a fairly
standard generator complies with HIR requirement if a low value of ceiling voltage is
specified for the particular machine.
Therefore, if the requirement for HIR is really necessary for the particular power system
then it is important that a carefully considered ceiling voltage is also specified as a
requirement. If a ceiling voltage is not specified, then it will be necessary for the machine
designer to assume a value of ceiling voltage and this assumption is likely to be a relatively
low value to enable a cost effective machine unless otherwise specified. (For comparison,
41
10
TR-69 — Grid Code Impacts on Generator Standards
when describing considerations for static excitation systems, IEEE Std. 421.2-2014 [59]
suggests that “….a ceiling voltage of 150% of the synchronous machine rated field voltage
is considered to be a minimum requirement.”)
As equipment satisfying HIR requirements can cause increased design and manufacturing
work compared to a more standard design then it is often useful to understand how close a
particular generator and excitation system design is to satisfying HIR requirements. A
generator manufacturer will be able to identify the associated ceiling voltage along with
the excitation system voltage response time of any particular generator design and this
information can be used to evaluate whether fully satisfying HIR requirements with a
particular ceiling voltage is really necessary or whether the more standard generator is
actually sufficient for the true needs of the power system. Frequently, HIR systems have
been initially specified without a detailed review of the costs and benefits but then respecified without the HIR requirement after a thorough cost benefit review of the
requirement has been completed.
A further consideration when specifying high ceiling factors is that with a thyristor bridge
typically used for such systems during normal operation, the firing angle for rated operation
of the generator would result in high losses in the snubber circuits of the thyristor rectifier.
These extra losses need to be carefully managed.
A combination of high ceiling factor and generators with a high rated output with a static
excitation system can sometimes lead to an AC input voltage greater than 1000V for the
thyristor bridge. This has to be considered by the design of the complete power part of the
excitation system including the excitation power transformer, power cables, thyristor
rectifier, de-excitation circuit and finally the rotor winding. Additionally, IEEE 421.3 [61]
and 421.4 [60] standards for medium voltage equipment must be taken into account.
The discussion above recognizes that vendors have standardized generator and excitation
systems, most of which were not designed to meet the ceiling levels associated with many
HIR specifications. Therefore, relative to these standard designs, an oversized and
therefore a more expensive exciter may be required which, for brushless systems, could
mean that a shaft mounted PMG becomes difficult or impossible to fit and therefore an
alternative means of providing the supply is likely to be needed.
Generally, many grid code or Transmission Operator connection requirements for fast
response or HIR excitation systems have been developed with very large generator units in
mind and these requirements frequently do not provide any significant benefit for smaller
units. In many cases a site-specific study can provide much greater benefits than simply
following blanket requirements for HIR from a grid code. This report supports the opinion
expressed by Hurley and Baldwin [62] that use of HIR systems should be limited to units
where there is a demonstrated need based on specific system studies and consideration of
alternative methods of stability improvement. Some grid codes do allow exemptions using
a waiver process depending upon size of machine, frequently using a study to show stability
margin is acceptable without the need for fast response or HIR, and this report encourages
that approach.
42
TR-69 — Grid Code Impacts on Generator Standards
c) Power Equipment: Independent power source
Grid codes sometimes specify an independent excitation system power source. Typically,
for brushless systems this is achieved using a PMG on the same shaft. Static excitation
systems are typically supplied using a shunt transformer which is inherently dependent
upon the voltage of the power system or generator terminals. Hence requirements for both
an independent power source and static excitation can be mutually exclusive for high power
systems.
For systems where a fault-tolerant supply is required, some generator vendors have
included windings in the generator or power current transformers have been added at the
generator stator terminals to provide current to the exciter during faults when the generator
voltage is low but current is high. (Typically referred to as a compound source [57]).
Theoretically an uninterruptible power supply could be an alternative to a PMG although
the authors of this report are not aware of an example installation.
d) Power Equipment: Short Circuit Clearance Duration
Generators designed according to standards such as IEEE Std. C50.13 [1] are required to
carry field current according to an inverse time relationship. The formula takes into account
that heat dissipation in windings is dependent upon the square of current and that it is
necessary to specify a time related limit for heat dissipation in excess of the continuously
allowable quantity.
However, some grid codes specify that generators and excitation systems must be capable
of providing high values of stator current and associated excitation current for much longer
than required by generator standards. For example, Russian GOST 533 [64] requires that
rotors of turbo-generators shall withstand double nominal stator current for 50 seconds.
Also, purchasers of generators often specify short circuit clearance (SCC) stator current
(line current) requirements of 2.5 or 3 per unit for 3, 5, or 10 seconds.
These requirements frequently mean that a generator field must carry a significantly greater
current than IEEE Standard C50.13 allows, if we use the C50.13 formula alone. (Actually
C50.13 does not specify current values until 10 seconds has elapsed but the formula is
continuous, so it makes most sense to consider the principle.) The chart below (Fig. 37)
shows an example of the problem.
The dotted line shows how the AVR over-excitation limiter (OEL) would be set to provide
an extended time SCC which is shown by the purple box. It can be clearly seen that the
IEEE formula line is significantly below the level required for SCC.
Historically it is understood that requirements for extended short circuit clearance times
were introduced with the aim of enabling protection relays to operate effectively to clear
power system faults. This subject has been widely discussed and reviewed with input from
the IEEE power system relaying and controls (PSRC) J subcommittee with no evidence
being presented to support any need for extended time SCC requirements. A resulting
consensus has developed that extended short circuit clearance times of 10 s or more do not
43
TR-69 — Grid Code Impacts on Generator Standards
need to be specified from a protection relaying perspective. Note that primary protection
typically operates in less than 5 cycles and backup protection operates in less than 2 s.
Field current ( % rated)
300
275
Fast OEL
250
IEEE C50.13 Limit, below 10s
Field current versus time to allow specified SCC
225
IEEE C50.13 Limit, 10s to 60s
200
175
150
125
SCC Required
0
2
4
6
8
10
12
14
16
18
20
22
24
26
28
30
32
34
36
38
40
42
44
46
48
50
52
54
56
58
60
100
Time (seconds)
Fig. 37: Excessive short circuit clearance time
While it is technically possible to satisfy requirements for extended short circuit clearance
times, any additional equipment size, mass and complexity required for implementation
are very unlikely to be justifiable in most cases. Therefore, this report proposes that grid
codes and specifications used for manufacture of generators should consider significant
reductions to times specified for short circuit clearance and associated rotor current.
Some grid codes require correspondence between over excitation limiter inverse time
curves and the short term field thermal capability curve provided in C50.13 capability. (e.g.
NERC PRC-019-2 [65] requirement). It should be straightforward for generator owners to
present information to satisfy this requirement.
The requirements for ceiling levels and transient stability considerations are discussed in
most power system textbooks. In the case of transient or first-swing stability, it is typical
that faulted elements are removed very quickly, even in the worst cases by backup
(delayed) protection and that stability-limited areas have suitable excitation ceiling and
gain according to grid code requirements. In these cases, field forcing will be limited to
much less than the 10 second start point of the field thermal heating curve and special
generator and exciter designs will not be required.
e) Power Equipment: Retrofits
Retrofitting or replacing existing equipment can be problematic when grid codes that were
not in place when the original equipment was delivered now require the use of different
technology. For example, if an existing dc excitation system is replaced using a new static
44
TR-69 — Grid Code Impacts on Generator Standards
excitation system, the excitation voltage waveform applied to the main generator field is
likely to include high harmonic content and the effect on the rotor insulation of the
associated rate of change of voltage needs to be carefully considered.
Other possible grid code requirement conflicts that need careful consideration when
retrofitting are:
•
•
•
•
Any increase in specified ceiling voltage.
Change of field circuit breaker type and location. As very few dc breakers are
available most retrofits are implemented using ac breakers on the ac supply side of
the excitation system.
Increased insulation classes and high potential test voltages.
Redundancy (n-1) in the exciter power stage. Typically, in all but the largest
systems, modern excitation systems provide simple dual redundant power stages.
Generally, the application of modern grid code requirements to excitation system retrofit
projects can result in non-standard products with significantly extra design risks and higher
costs often without significant benefits. Therefore, it is recommended that grid codes adopt
a policy of allowing “grandfathering” whereby equipment may be provided which is
equivalent to the original equipment although actual implementation details may differ.
3.3.3 Excitation System Functional Design
a) Functional Design: Control Modes
Excitation systems include a variety of control modes including AVR, power factor (PF),
reactive power (VAR), and manual (set point field voltage or current). Grid Codes typically
dictate the appropriate control mode and notifications required when a change of control
mode occurs.
Taking North America as an example, NERC VAR-002-4.1, [66] requires that all
applicable units be operated in automatic voltage control mode, controlling generator
voltage. IEEE Std. 1547 [67] in conjunction with local distribution system operator
requirements dictate unit controls at the distribution system level in either power factor or
reactive power set point or voltage (volt-var) control mode.
There are two main considerations dictating the choice of excitation control mode:
On the sub-transmission grid or distribution system, generators are primarily used for loaddisplacement. (i.e. These independently owned units are not primarily run for selling
electricity to the grid but to provide electricity and sometimes steam to their industry host.)
Typically, these units are required not to be controlling the line voltage and must disconnect
for any disturbance for safety and control reasons. Conversely on the bulk grid, root cause
analysis of several voltage collapse incidents revealed, see [76],[77], that many new gas
turbine and combined-cycle units were operated by default in constant PF (usually unity)
control and did not respond to system voltage disturbances by providing reactive support
in the long term. In fact, constant PF control is worse from a system support view than
45
TR-69 — Grid Code Impacts on Generator Standards
manual constant field voltage control, because constant PF or reactive power control will
reduce unit excitation and hence reactive support during system low voltage events,
exacerbating the disturbance. Because this is (usually) a control mode and not a hardware
design issue, even legacy generators must comply with this rule immediately.
b) Functional Design: Power System Stabilizer (PSS) Requirements
Stability is a power system issue. System operators are tasked by grid codes with
calculating load, voltage, frequency and stability limits and ensuring that operation is
maintained within those limits. Generator owners on the other hand, are tasked with
providing and operating equipment to allow stable operation, but usually they do not have
the mandate nor the tools and information to perform stability studies. Instead, stability
requirements include acceptance criteria which may, or may not, be easily evaluated by the
generator and equipment vendor.
Typically grid codes require that a PSS must be provided and be in service when the
generating unit is on line. An example grid code requires that the stabilizer design must
match that shown in IEEE recommended practice 421.5 [57] type PSS2C with two inputs:
electrical power and speed or compensated frequency. The detailed PSS requirements are
typically as follows: The positive and negative output limits not less than ±5% of generator
terminal voltage reference. The stabilizer output must be an input of the automatic voltage
regulator. The stabilizer tunable phase compensation must be within 30° of the required
closed-loop phase lag of the automatic voltage regulator with the unit on line at no load
and with the PSS out of service over a range of 0.2 and 2.0 Hz frequency. Sufficient gain
must be in service to provide a damping ratio above 0.1 or as limited by exciter modes of
oscillation.
In the preceding example, the design of the PSS is specified by reference to a standard.
However, the nature of tuning and testing to prove compliance is typically left to the
generator owner or vendor. A range of frequencies has been provided in order to capture
higher-frequency local modes and lower frequency inter-area oscillation modes. Some
jurisdictions only make specific requirements for inter-area modes, as local mode stability
is observable and part of equipment commissioning and testing (a unit that is not local
mode stable could not be operated).
The figure below shows a common test as described in the example above. The unit has
been synchronized and kept at low load. Its AVR has been tuned to meet transient
performance requirements listed in another part of the grid code. The unit is tested by
injecting a varying frequency signal (white noise, swept frequency, or discrete frequencies
depending upon grid code requirement) at the point where the PSS would be connected,
and the resulting phase lag (inverted in the plot), is shown by the circles. The PSS settings
are then selected to produce the dashed line phase compensation to be within the required
30-degree margin over the mandated frequency range. Should the unit’s local mode of
oscillation be greater than 2 Hz, the PSS tuning would have to be adjusted accordingly.
46
TR-69 — Grid Code Impacts on Generator Standards
100
measured phase lead requirement
selected PSS compensation
Phase (degrees)
75
50
25
0
0.1
1
10
Frequency (Hz)
Fig. 38: PSS phase compensation
While this figure confirms the phase compensation requirement, another test is required to
prove the damping contribution. In general, it is not possible to prove inter-area mode
damping from tests at the unit itself. The typical test performed is to provide a plot or series
of plots with increasing stabilizer gain to show its beneficial effect.
47
TR-69 — Grid Code Impacts on Generator Standards
On-Line Step Response
Stabilizer Gains=1 and 10
Active Power
(pu)
1.00
0.95
0.90
0.85
0.010
delta speed
(%)
0.005
0
-0.005
-0.010
-0.015
0.010
PSS
(pu)
0.005
0
-0.005
-0.010
0
2
4
6
8
10
Time (seconds)
Fig. 39: One-line step response with PSS
The periodic re-verification requirements of grid codes imply that time and frequency
domain testing and recording facilities are included in excitation equipment or suitable
analog signal inputs and outputs should be available to connect external test and recording
equipment. Such facilities are not typically mentioned in either grid codes or generator
owner requests for proposal for new excitation systems and these features should be
explicitly mentioned in both.
c) Functional Design: Signal Injection for PSS Validation
Many grid code requirements demand demonstration of power damping provided by the
PSS. This demonstration may be accomplished by means of comparison of the power
48
TR-69 — Grid Code Impacts on Generator Standards
damping frequency response with activated and deactivated or reduced gain PSS. When
the PSS is activated, the amplitude of the measured transfer function must be smaller than
with the deactivated PSS in the frequency range of interest, which depends upon grid code
requirements (typically 0.2 Hz to 2 Hz). It is crucial to asses not only damping at local
mode oscillation (which is easily checked by step-response tests), but also the performance
at inter-area oscillation frequencies, which may be achieved by the presented validation
procedure.
In order to measure the power damping frequency response, a signal is injected to the AVR
summing point and this signal as well as electrical power and other signals are measured.
The test setup is indicated in Fig. 40.
Data
logger
Vinj, measured
+
Vinj
VT
PT
AVR
GEN
EFD
Grid
PSS = OFF
resp.
PSS = ON
Fig. 40: Determination of the power damping frequency response with PSS activated and
deactivated
The theory of PSS tuning requires that determination of phase compensation is performed
with the generator operating on line at as near as possible to zero electrical power output
as described by Heffron and Phillips [68] and de Mello and Concordia [69].
After the required phase compensation has been determined and PSS tuning has been
completed grid codes frequently require PSS performance to be demonstrated, also using
signal injection, but this time at nominal active power and typically with near unity power
factor.
The reasons why in practice this test is executed at nominal operating point are as follows:
•
•
•
The impact of the PSS is demonstrated at nominal operation conditions.
Typically, the PSS is required to be deactivated at low active power levels.
Continued operation at low power levels is often not desired (e.g. hydro power
plants or reciprocating engines)
49
TR-69 — Grid Code Impacts on Generator Standards
In order to perform this test on site, sinusoidal or white-noise signals or a pseudo random
binary sequence signal [70] is injected to the AVR and added on the AVR summing point.
Therefore, the AVR needs to have the capability to accept this signal. When injecting the
signal, care has to be taken that no resonance frequency is excited, that the machine remains
within its safe operating area and that the amplitude of the active power oscillations
remains within its allowed limits. With a weighted band-limited white noise signal or
PRBS injection, this risk is minimized. In case of weight band-limited white noise or PRBS
injection, Fourier analysis of the injected signal at the AVR summing point and the
measured electrical output power signal yields the requested transfer function. When using
a weighted band-limited white noise signal, typically a higher gain is used for low
frequency signals to ensure sufficient signal level. Washout filters are used to cancel out
DC components. The amplitude of white noise used at high frequencies is low to avoid
excitation of resonance frequencies.
For all methods (sinusoidal as well as white noise or PRBS injection), it is recommended
to feedback the injected signal through the AVR and use it for the calculation of the transfer
function in order to account for the effects of filtering. (Compare Fig. 40.) The injected
signals as well as the measured output signals need to be supervised to avoid too high
oscillation amplitudes and to ensure safe operation.
The trace of gain (compare Fig. 41) of the resulting transfer function indicates the damping
effect of the PSS over the requested frequency range with the PSS typically providing a
positive influence between 0.2 Hz and 2 Hz. The selected PSS parameters, as well as the
frequency measurement signal which is used as PSS input, have a major influence on the
PSS damping which is achieved. Oscillations at the lower frequencies in the abovementioned range are influenced considerably by the PSS input frequency measurement
(e.g. for the IEEE PSS2C [57] structure see comparison in [71]).
ΔPT / Δ Vinj,measured
System without PSS
Decent tuning /
frequency meas.
Poor tuning /
frequency meas.
Magnitude (dB)
30
20
10
0
-10
typical range of optimization
-1
10
0
10
Frequency (Hz)
1
10
Fig. 41: Example comparison of power damping frequency response with deactivated PSS
versus activated PSS
50
TR-69 — Grid Code Impacts on Generator Standards
An example interaction between the PSS and reactive power is shown in Fig. 42. for an
inter-area mode disturbance initiated by a line switching test. The PSS is providing
damping of both local and inter area modes. The resulting terminal voltage and reactive
power variations may be seen in the figure. This test was not performed to satisfy a grid
code requirement; rather the PSS was designed and tuned specifically for this common
event which, without a PSS, resulted in line and customer load trips.
Active Power
(pu)
0.88
0.86
0.84
0.82
0.80
0.78
Reactive Power
(pu)
0.08
0.06
0.04
0.02
0
-0.02
Terminal V
(pu)
1.00
0.99
0.98
0.97
0.96
PSS Output
(pu)
0.04
0.02
0
-0.02
0
2
4
6
8
10
Time (seconds)
Fig. 42: PSS action on inter-area mode disturbance initiated by a line switching
Other aspects of tuning and commissioning are also important when applying a PSS, such
as mitigating the effect of fast load ramping or mechanical turbulence in hydro units, but
these are not discussed here.
51
TR-69 — Grid Code Impacts on Generator Standards
d) Functional Design: Limiters and Protection
In addition to the regulating functions described to this point, most excitation systems are
also equipped with excitation limiters. These limiters serve to limit excitation to within
acceptable bounds, as appropriate, to protect equipment and avoid exciter and/or generator
trips.
Grid codes may impose requirements for coordination of limiters, protection and generator
capability [65]. Some will also impose minimum requirements on the generator’s over and
under excited capability. For coordination, the limiters should operate before the relays and
the equipment’s capability limits should be respected in both short term and in steady-state.
Excitation functions that limit or override the usual AVR response must coordinate with
equipment capabilities (the most limiting of the generator, exciter power source,
transformers, etc.…) and with internal and external protections and system voltage and
frequency ride-through requirements. This task is a challenge because excitation controls,
power equipment, and protection are typically different departments in a utility company.
Compliance requires coordination and communication between equipment vendors,
transmission operators, and within departments of the equipment owner. In the authors’
experience, proving and documenting coordination usually falls on the excitation system
provider.
Often equipment damage or heating curves are not available, and in this case applicable
protection standards such as IEEE C37.102 [72] and IEEE C37.106 [73] must be used as
guidelines for settings.
Some types of excitation limiters may be prohibited or may be mandatory. Thus excitation
vendors will have a variety of control and limit functions available. Use and setting of these
functions must be determined by reviewing the applicable Grid Codes. Note that this is not
the way legacy excitation systems were commissioned and tuned. Typically field staff set
up systems using local measurements and consultation with power plant staff, but not in
conjunction with Grid Codes or stability studies.
Some highlights of NERC PRC-019-2 [65] are listed below:
1.1. Assuming the normal automatic voltage regulator control loop and steady-state system
operating conditions, verify the following coordination items for each applicable Facility:
1.1.1. The in-service limiters are set to operate before the Protection System of the
applicable Facility in order to avoid disconnecting the generator unnecessarily.
1.1.2. The applicable in-service Protection System devices are set to operate to isolate or
de-energize equipment in order to limit the extent of damage when operating conditions
exceed equipment capabilities or stability limits.
These rules have the following implications:
52
TR-69 — Grid Code Impacts on Generator Standards
R1.1 Assuming AVR operation, regulating generator stator voltage. Manual, fixed field
control is not allowed by NERC VAR-002 [66]. Thus, no traditional SSSL is to be shown
based on constant field voltage assumptions.
R1.1.1 - The in-service limiters always act before the protection systems.
R1.1.2 - Protection systems must limit the extent of damage when operating conditions
exceed equipment capabilities or stability limits.
Thus, it is conceivable that some protection elements are set beyond the equipment
capability and, thus, the unit would operate for a certain period of time beyond its steady
state capability or stability limit. If the risk of damage is considered acceptable by the
equipment owner, the requirement from NERC PRC-019-2 [65] is met.
For brushless exciters, there is an additional complication in that the over excitation limiter
works through the main exciter field. As a result, coordination with the generator rotor
heating limits of IEEE C50.13 [1] requires knowing the main exciter saturation
characteristics, since the generator field quantities cannot directly be measured. For retrofit
voltage regulators, the original main exciter equipment saturation curves must be provided
by the generator owner. Even for new equipment, this information may be difficult or
impossible to obtain.
It is critical that all limiters be coordinated with the generator's capability and the protective
relay settings, allowing the excitation system to exploit the full generator capability to
support power system requirements.
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TR-69 — Grid Code Impacts on Generator Standards
Table 3 summarizes the types of limiters that are available as options on many excitation
systems and the associated protective relay functions and equipment limitations.
Some digital excitation systems are now also providing some protective functions that may
duplicate those that are implemented externally with standalone relays. It is important to
remember that if these functions have been enabled, they must be included as part of the
coordination exercise and their settings documented.
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TR-69 — Grid Code Impacts on Generator Standards
Table 3. Available Excitation System Limiters and Capabilities
Equipment Capability
Excitation Limiter
Protective Function
•
•
field winding short-term thermal
capability (e.g. ANSI C50.13 for
cylindrical rotor)
excitation system current rating
Over Excitation Limiter
(OEL) / Maximum
Excitation or Field
Over Current Limiter
• O/C (50/51) on excitation
transformers
• dc O/C or O/V timed relays (exciter)
•
•
•
generator flux limit
transformer flux limits
generator continuous voltage limit
V/Hz Limiter
V/Hz (24)
O/V (59)
•
•
stator thermal rating
generator step up transformer current
rating
Terminal Voltage
Limiter
Stator Current Limiter
•
•
core-end overheating limit
exciter minimum field current limit
Under-Excitation
Limiter
55
•
•
•
•
•
Backup voltage-restrained or
voltage-controlled O/C (51V)
Backup distance protection (21)
Stator thermal overload relay (49)
(40) Loss-of-excitation relay
Loss-of-conduction detection
(exciter)
TR-69 — Grid Code Impacts on Generator Standards
3.3.4 Excitation System Grid Code Applicability & Acceptance Procedures
a) Applicability of Grid Codes
The applicability of a grid code to a generator depends on technical factors as well as the
phase-in dates of the requirements.
Most grid codes have an enforcement date with a period of time in which a generator owner
must bring all of its applicable facilities into compliance with the requirements, (e.g. over
a 10 year period ending “date”, the generator owner must bring 100% of its applicable
facilities into compliance with 40% within 4 years, 60% within 6 years, 80% within 8 years
and 100% by 10 years).
The technical requirements are usually dependent on the output of the plant, typically
expressed as units greater than a threshold in MVA and/or plants greater than a larger
threshold in MVA.
The applicability may also depend on connection point, usually specified in terms of the
transmission voltage at the high side of the generator step-up transformer. In North
America, plants or units connected at greater than 100 kV transmission voltage are
considered as connected to the bulk grid. In this case, some grid code requirements may
apply even if the unit or plant MVA ratings are below those thresholds.
Finally, applicability may depend on the in-service date of the equipment compared with
the grid code approval date.
b) Existing Equipment
In the simplest cases, a new generator installed after the approval of a grid code must
necessarily meet all the applicable requirements at the time of installation. Conversely, a
facility which pre-dates the grid code may be “grandfathered” into the system and not have
to meet any performance requirements. Frequently there will still be simulation modeling
and data validation requirements in this case, but it is not necessary to alter or replace the
equipment in an older plant in order to meet requirements which came into effect after the
plant was built.
There are some exceptions to the above two simple cases.
Some requirements may include older units if the requirements are related to modes of
control or reporting or equipment which is considered to be routinely adjusted and
calibrated. For instance, in North America it is required that all units connected to the bulk
electric system be operated with their excitation in automatic voltage regulator mode
controlling stator voltage, and not in power factor or reactive power set point modes.
Should the operator’s control mode be one of these prohibited modes, it would be required
to change it to meet the voltage control requirement. Similarly, it may be required to change
56
TR-69 — Grid Code Impacts on Generator Standards
protective relay and/or excitation limiter coordination to meet reactive power, voltage or
frequency ride through requirements.
Finally, retrofits of obsolete equipment or other changes to controls or ratings in an existing
plant usually require any changed equipment to meet the present rules, even if the original
equipment did not. This should be considered carefully when writing specifications for
new equipment in a plant to make sure that the equipment purchased is not simply a “likefor-like” replacement, but that it also meets applicable grid code requirements.
Grid Codes sometimes don’t include necessary acceptance criteria for each requirement.
For example, the goodness of fit between measurements and simulation models is typically
left to the engineering groups tasked with performing the measurement and modeling. This
has been discussed during grid code development and usually has been intentionally
omitted because of the variety of equipment designs and test and measurement techniques
which may be appropriate or available to perform the work.
c) Confirmation of Small Signal Performance
Often in grid codes rise time, overshoot and/or settling time are used to specify dynamic
performance of the excitation control system. Alternatively, the frequency response
characteristic of the linear system either open-loop or closed-loop can be used as
performance indices as per IEEE Std. 421.2 [59].
Grid code dynamic performance requirements based on transient and small signal stability
considerations may result in demanding constraints on the excitation control system
regarding time delays of digital control systems and noise generated by transducers and
signal conditioning.
It is not inherently guaranteed that a new control system will meet the latest grid code
requirements. As technology has moved from magnetic equipment to analog electronics to
digital electronics, factors such as cost, weight, commonality of hardware and software or
other issues may result in standard available designs which do not meet the most stringent
performance requirements. These requirements must be clearly communicated in
equipment specifications. Special care must be taken when applying digital designs –
explicit recommendation needed here to clarification. Type tests need to be defined so that
the equipment can be assessed before the equipment is installed on the unit. Therefore,
updates to IEEE Std 421.2 [59] and Std 421.4 [60] need to be considered. Some grid codes
define acceptance criteria but not all.
d) Guidelines on Acceptance Criteria
Those tasked with performing validation tests should have guidance on the allowed or
required test conditions to confirm compliance and, in particular, how to confirm
compliance for unusual system conditions (e.g. inter-area oscillation damping, off-nominal
frequency or voltage, transients). This will necessarily be a balancing act; requirements
which are too prescriptive may make it difficult, if not impossible, for some facilities to
comply, while lack of guidance or vague requirements may result in disputes between the
57
TR-69 — Grid Code Impacts on Generator Standards
testing group and regulatory group as to whether the intent of the requirement has been
met. Standards groups such as IEEE and IEC, have useful task force papers and guidelines
which most test and modeling groups reference in the absence of specifics in the grid codes,
for example IEEE Std 115 [74], Std 421.2 [59] and Std 1110 [73].
3.3.5 Conclusions and Recommendations on Excitation Related Issues
•Site-specific studies may reveal cost-effective excitation options that maintain system
stability.
•Grid codes alone do not provide enough information to specify the design, studies, and
testing requirements for excitation systems. Also, existing technical standards do not
fully address the information gaps.
•The information required to evaluate excitation system design, functions, and settings
involves details about the generator unit, turbine, controls and protective functions and
analysis by many parties.
•Studies, guidelines, and additional information are required prior to issuing a request for
quotation (RFQ) for new excitation systems.
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TR-69 — Grid Code Impacts on Generator Standards
3.4
Operating New and Existing Generators to Support the Energy
Transition
3.4.1 New Service Factor Requirements
As demonstrated in Fig. 43 [25], over the past 10 years there has been a shift in how large
central station power plants are operated, spreading across the service factor spectrum from
an earlier concentration in base load and intermediate load applications (the blue ellipse)
to a much more widely spread spectrum that includes base load, intermediate load, peaking
duty & standby (magenta ellipse).
Fig. 43: Changes in operating mode of 32 power plant units over the period from 2008 to
2012 in southwestern Europe due to the deployment of renewable power generation [25]
With this spread in service factors, generators are also experiencing intensifying
intermittency of operation. Even units with ratings in excess of 400MW now experience
on-off-on-off duty in a day, and multiple large-scale load swings when on-line.
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TR-69 — Grid Code Impacts on Generator Standards
3.4.2 New Duty Cycle Requirements
Fig. 44: Changing speed, power and reactive power in typical daily demand profile [25]
The sample load profile Fig. 44 of one subject generating station exhibits the several startstops / day, depending on renewable energy production, as well as fast and frequent steps
in MW to balance weather dependent renewable energy. Further, there is continuous
MVAR variation to stabilize fluctuating grid conditions.
Treatment of such duty cycles is quite limited in today’s machine standards. The IEEE
C50.13[1] standard for round rotor synchronous machines does not address duty cycles at
all. The IEC standard 60034-1[2] declares that it is the responsibility of the purchaser to
declare the duty. The purchaser may describe the duty by several methods, and IEC 600341 provides a series (S1-S10) of idealized duty cycles. By default, the duty cycle is assumed
to be S1, which is a steady fixed load equal to the unit rating, as this is considered to be a
worst case, at least from a thermal aging perspective. However, this ignores the differential
thermal expansion that results from load swings that can impact unit life. Indeed, none of
the available duty cycles in the IEC60034-1 reflect anything like the example shown above.
Clearly the equipment standards need to either develop new idealized duty cycles, or
operators will need to provide real or simulated load profiles, if manufacturers are to
explicitly consider the duty. Ideally, the treatment of duty cycle will be done in a
harmonized manner through the cooperation of Cigre, IEC & IEEE.
Extending considerations beyond the impact of duty cycle, consider the impact of variable
loading on other specified generator characteristics, such as efficiency. This may be of
particular interest and concern in cases when the generator is being specified for
replacement of an existing unit, independent of the prime mover, for example. In such
cases, comparison of generator efficiencies explicitly may weigh on the equipment
selection, whereas for most cases in which both the prime-mover and generator are
supplied as a package, the combined efficiency is of primary consideration.
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TR-69 — Grid Code Impacts on Generator Standards
Fig. 45: Relative frequency of operating point [25]
As illustrated in Fig. 45, on a reactive power capability diagram (where abscissa is MW
and ordinate is MVAR - positive when supplying reactive power and negative when
absorbing reactive power), the operating point moves throughout the limits of the diagram
agreed between purchaser & manufacturer.
For generators purposes, the (P, Q) of the machine is considered, while the (U, Q) is the
curve given at the Grid side; both should be considered in the future in order to handle to
topic properly, the new Gridcodes having a direct impact on the (U,Q) curves.
Color coding is used to indicate the percentage of time spent in each “bin” of about 3%
MVA range. Red dots mean a lot of time spent at that load point, blue means less time.
Consider a sample load duty cycle, reflective of a unit with the following characteristics:
•
High number of stop-start cycles
•
Operation over the load range, but infrequently at rated load
•
High share of reactive power for grid stabilization
•
Full use of the under-excitation capability
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TR-69 — Grid Code Impacts on Generator Standards
3.4.3 Existing Generators Flexibility Requirements in Grid Codes
The introduction of new service factors and duty cycles described above requires higher
flexibility in the operating conditions of the generating plants which may also affect the
performance, reliability, life span and maintenance needs of already existing generators.
In addition to more frequent and larger power fluctuations, high load ramps and more
numerous start-stop cycles, it is also necessary to accommodate more frequent and longer
turning gear operation as well as minimum load regimes or shut-down periods. Overall
utilization of thermal power plants is only partial or very low, resulting in uneconomical
operation. Coal and gas units change from base to peak load condition and even nuclear
units switch to load change mode. The operating regimes of conventional power plants can
differ greatly, even if these generators are of the same type or output range [18] - [22].
Machines designed strictly in accordance with IEC 60034 and IEEE C50.13 standards may
not be able to meet these new operating conditions and can be endangered in terms of
reliability and reduced life span. This means that with the necessarily increased
maintenance costs, conventional plants are in effect subsidizing new variable energy
resources.
3.4.4 Possible damage scenarios
The paragraphs below explain how new operating conditions can have significant
consequences for large turbo generators.
3.4.4.1
The Effects of Frequent Starts and Stops
Existing plants should suit every scenario, from base load to daily start. Some analyses
[27], [28] indicate that in the future the major part of the synchronous power generating
capacity will likely not be continuously required and up to 100% of the synchronous
generating fleet will have to start and stop on a daily basis. That means that power plants
originally intended to operate as base-load units (with very few starts per year) could be
needed to start/stop roughly 300 times per year. This shift in the operational profile from
base load to intermediate and peak regimes can already be observed for power plants in
Europe, which change to daily start and stop (DSS) or “two shift operation” (shut-downs
every night and/or weekend) [25].
The numerous starts and stops expose the equipment to considerable stress and leads to
reduction of lifetime. Low cycle fatigue stresses due to the increased start and stop
operation, adversely affects many generator rotor components, especially those of the rotor
winding causing premature failure and an open circuit condition, forcing the unit off-line.
The thermal cycling that occurs during start-up, shut down, and related load changes
involves components aging and possible damage to the conductors and the insulation [22],
[25], [30], [31]. Equipment failures have also been recorded because of alteration of
maintenance habits (even after an opposite change, when plants used to operate in daily
start regime suddenly shift to base load).
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TR-69 — Grid Code Impacts on Generator Standards
3.4.4.2
The Effects of Load Ramps
The combined cycle power plants must be able to cope with fast response from part-load
and quick start-up from shutdown, to support grid frequency disturbance restorations
[32].
The steep load ramps are estimated by some studies as up to 24% of rated MW per
minute[33].
In an extreme case of island formation within the grid with a sudden reduction in the
power demand, it may be necessary to run down the plant from full to minimum load
within just a few seconds (for instance, the UK Grid Code requires running down to at
most 55% of its rating within 8 seconds [27]).
The high and frequent output gradients cause fast expansion and contraction of the
windings, (i.e. thermal cycling and correspondingly high thermo-mechanical stress). This
results in accelerated aging in older generators that have previously been operated in base
load, potentially leading to gradual fatigue cracking of stator insulation or abrasion of
rotor insulation. Furthermore, the dielectric losses in the insulation may increase and this
could lead to accelerate (visually detectable) aging [22], [24], [25].
3.4.4.3
The Effects of Power Factor
Grid codes may specify the power factor range, usually at the point of connection on the
transmission system (instead of at generator terminals, which is the way used by
generator standards). These two power factors are different, because of reactive power
absorbed by the unit main transformer (plus the small power consumed by auxiliaries).
[13]
At the same MW, operation at lower overexcited power factor (higher reactive power)
requires higher stator current and an increase in the field current [35]. Low leading power
factors of less than 0.95 (higher negative/absorbed reactive power) may lead to high
magnetic flux in the core-end region [36].
3.4.4.4
The Effects of Steady State Conditions
Steady state conditions should be addressed considering the impact on the magnetic
fluxes and temperatures in the synchronous machine (stator bars, magnetic circuit),
vibrations of the end-windings, etc.
Any upgrade may be an issue on existing power plants. This upgrade may be planned
during a planned stoppage of the power plant. Upgrade activities to be performed have to
be addressed (new flux shield installation as an example, to further optimize operating
conditions, with minimized costs for the plant owner). Investigations should be carried
out to determine if such upgrades are feasible technically and economically.
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TR-69 — Grid Code Impacts on Generator Standards
3.4.4.5
The Effects of High Voltage at Low Speed
Combination of overvoltage and under-frequency operation (i.e. high V/Hz values) may
have a notable impact on flux density in the stator core. For instance, wider frequency
range (47.5 Hz - 51.5 Hz) and elevated voltage range (85% - 115%) as required by the
European Network Code, considerably increases the risk of stator over-fluxing [35].
Higher flux density results in overheating risks. As a result of stator over-fluxing, the
leakage flux will be forced into the stator frame resulting in eddy currents that heat the
core support structure, key bars, etc. [22] - [24]. The rotor must provide this magnetic
induction, which may result in higher rotor currents and possible rotor overheating [25].
3.4.4.6
The Effects of Voltage Variations
Virtually all generator standards specify that the generator must be capable of continuous
operation at terminal voltage from 95% to 105% of rated value, while some grid codes
appear to stipulate wider ranges. However, it is extremely important to define if the
voltage range is at the system connection point or at the generator terminals. A generator
has the capability to adjust its terminal voltage by producing or absorbing reactive power.
For example, it can operate at 0.85 lagging power factor (to increase the generator
voltage in case of low system voltages) or at 0.95 leading power factor (to reduce the
generator voltage in case of high system voltages) [34], [36], [38]. A main transformer
equipped with on-load tap changer will further facilitate the grid voltage variations.
3.4.4.7
The Effects of Frequency Variations
The energy transition and some grid codes are significantly expanding operating
frequency requirements beyond the continuous ±2% range and the short term +3%/–5%
range defined by IEEE C50.13 and IEC 60034-3. Over-frequency and under frequency
conditions are symptoms of an excess of generation and are usually limited in extent and
time by high-speed modern governors and load response. Under-frequency, on the other
hand, indicates a shortage of generation and can continue for longer duration (until load
shedding) [34].
Implications of these expanded frequency limits include potentially compromising the
reliability of the turbine (cracked blades) and performance of auxiliary systems
(circulating water pump, feed-water pump, etc.) [23]. Generator field current flowing at
decreasing speeds may cause rotor thermal overload and major damage. The underfrequency possible consequences are also excessive V/Hz causing possible generator and
transformer core damage as described above. Note this issue is also relevant for new
machines (See section 3.1.1 . This applies to all / most subsections of this section).
3.4.4.8
The Effects of Fault-Ride-Through
Fault-ride-through has been incorporated in many grid codes worldwide as a voltage-time
curve by which mainly the generator should remain in synchronism without pole slipping
and the auxiliary induction motors should not stall or trip. If the fault clearing time is
shorter than the fault critical clearing time, the synchronous generator will stop
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TR-69 — Grid Code Impacts on Generator Standards
acceleration and induction motors will deal with slip increase and voltage drop,
remaining stable as they reach new post fault operating conditions[39]. Additional power
plant components and aspects should be considered, like boiler feed water, circulating
cooling water, turbine generator lube and seal oil, fuel delivery systems, protection
systems, automatic bus transfers, etc.[40], [42].
Generators designed per standards IEEE C50.13 or IEC 60034-3 do not automatically
comply with the fault-ride-through requirements [23] and the issue may be far more
troublesome in case they are imposed retroactively on an existing power plant. Long
fault-ride-through times up to 250 ms may induce significant high torsional stress at turbo
set shaft and risk of material cracks at rotor flanges [22].
3.4.4.9
The Effects of Ceiling Voltage
One of the possibilities to improve the fault-ride-through capability is a faster adjustment
of the field current and this can be obtained by higher ceiling voltage of the excitation
system. Increase of ceiling voltage has only limited effect on RoCoF withstand capability
(above ceiling factors of 2.5-3.0 no significant increase of the maximum RoCoF
withstand capability is expected [43]).
High ceiling voltage impacts the rotor ground and turn-to-turn insulation systems, which
will be exposed to higher voltage levels and high frequency voltage spikes. In addition,
higher ceiling voltages may also influence other components, like the excitation
transformer. [23], [35].
3.4.4.10 The Effects of High Speed Reclosing
The major effects of auto-reclosing on turbo-generators are high mechanical torques in
the shafts and high forces on generator end-windings. Sometimes various solutions may
be implemented, like use of sequential reclosing (reclose initially from the remote end of
a line and block reclosing at the generating station if the fault persists) [23],[36],[43] .
3.4.4.11 The Effects of Harmonic Currents
If the harmonics imposed by the system exceed the total harmonic distortion (THD)
defined in both IEEE and IEC standards, then these also need to be considered, possibly
resulting in a decrease in the generator negative sequence capability (also defined in
standards)[23].
The harmonic currents need to be considered for their additional heating effect in the
damper system and on the rotor surface. Typically, if the additional heating of the rotor
exceeds 10%, then a reduction in the declared negative sequence capability must be
imposed or additional measures can be necessary to deal with existing rotor damper
losses and rotor surface circulating currents (e.g. modifying the damper concept or
addition of filters) [23].
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TR-69 — Grid Code Impacts on Generator Standards
3.4.4.12 The Effects of Other Factors Including Steady State Conditions
The new grid codes and flexible operation stress also the plant auxiliary systems. For
instance, motors will be exposed to increased electrical and mechanical stresses due to
the number of switching operations [44][40].
Not only do the new grid codes ignore the existing generator standards, but some of their
requirements (like the imposed voltage range) are not according to the international
standards for transmission and distribution equipment [45]. Moreover, the existing plants
should be evaluated periodically to assure appropriate protection coordination.
Generator protection relays and excitation system limiters should be coordinated with
grid protection (e.g., frequency relays vs. load shedding programs) and should consider
that old plants cannot typically reach the original unit capability curves because of
various aging limitations [42].
In many cases, the results of new operating regimes are worsened because they are
accompanied by less frequent or reduced maintenance activities [44][40].
3.4.5 Impact on Efficiency
With large variations in load, generator losses vary, resulting in significant changes in
generator efficiency. While the overall generating plant efficiency is largely dictated by
the cycle thermal efficiency, review of the generator’s losses versus load is instructive.
Regarding efficiency, as shown here in this simple relation between efficiency and MVA
loading at a constant 0.90 power factor, when an operating point varies over a wide MVA
range, efficiency of a turbo-generator varies noticeably.
Fig. 46: Efficiency variation with constant and varied H2 over pressure
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TR-69 — Grid Code Impacts on Generator Standards
Notice variations of efficiency as a function of MVA shown in Fig. 46 at a fixed power
factor for an example (an imagined) 60 Hz, 26 kV, 1000+ MVA hydrogen-cooled turbogenerator with water-cooled stator windings.
Fig. 47: Weighted average efficiency with fixed H2 overpressure
Returning to the reactive capability view in Fig. 47, on the left is efficiency as function of
MW and MVAR over the whole reactive power capability diagram for a situation where
H2 gauge pressure is kept at 75 psig even when MVA loads move well away from rated.
Note 98.96% efficiency at rated MW & power factor. The isolines map contours of
constant efficiency. At select operating conditions, nearer to unity power factor, the
efficiency exceeds 99.1%.
On the right is an example map of percentage of time this example generator might be
operated for load points within the reactive power capability diagram – like the figure
shown previously.
A weighted average efficiency may be determined by multiplying the left pattern by the
right one, yielding a value of 99.08%, which is 0.12% more than 98.96% exhibited at rated
load.
As already observed, “grids of the present” and certainly more so “grids of the future” will
likely see operation of turbo-generators over a wider range of load conditions.
Therefore, it may be appropriate to introduce the option to specify several expected
operating points and the % of time expected to operate at those points. In the example
below, 8 operating points with various percentages-of-time specified for each operating
point are defined (Sum of the numbers in the yellow boxes equals 100%.).
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TR-69 — Grid Code Impacts on Generator Standards
Fig. 48: Example showing weighted average efficiency
Again, considering the 1000+ MVA turbo-generator discussed above, the weighted
average efficiency is 99.06% vs 98.96% at rated load & power factor.
As noted earlier, although the standards are silent regarding such efficiency considerations,
there are bids, such as those for generator-only supply, that have required such evaluation.
Under these cases, the generator efficiency may be a more significant differentiator. If
adopted as an allowable, but not required, practice in standards, fewer points may be
specified.
3.4.6 Data Gathered Demonstrating the Effects of New Grid Demands
Table 4 and Table 5 show examples of how different OEMs collected the main expected
effects on generator components. For the overall generator, the accumulated damage may
be four times higher in the case of two shift operation than on base load. For the stator,
two shift operating regime results in doubling the damage rate, while for the rotor it can
increase up to seven times [47].
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TR-69 — Grid Code Impacts on Generator Standards
Table 4. Effects of New Grid Demands on Generators [50],[45]
Increased Requirements Due to
Flexible Operation
Physical / Technical
Challenges
Affected Generator Components
Main bushings of stator winding
Carbon brushes and slip rings of static excitation
Fast active & reactive
load changes
High
thermomechanical tension
Stator core end zones (stepped teeth)
Stator winding, especially end winding baskets
Rotor winding, especially end-windings
covered by retaining rings
Complete stator winding
Load ramps up to 24%
of rated MW / min
Thermal cycling
Complete rotor winding
End teeth, press finger, press plate
Under-excitation
High magnetic flux in end
region
Stator winding in stepped core area
Stacking beams at stator core back
Rotor winding
Over-voltage
High magnetic flux
density
Stator core insulation
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TR-69 — Grid Code Impacts on Generator Standards
Table 5. Impact of Operating Mode Relative to Base Load (from [47])
3.4.7 Conclusions on Operating Generators to Support the Energy
Transition
In conclusion, comprehensive updates to equipment standards and grid-codes should
reflect the energy transition by addressing issues such as enhanced operational flexibility,
duty cycles and weighted efficiency. It is particularly important to consider influence the
effects upon the various components of existing / old generators.
To mitigate the risks, the utility (together with the OEM) should complete a detailed
techno-economical study intended to prepare the generators for the new operating
conditions and possible lifetime extension. This work should include, for instance: [21]
[23][24][25]
Analyze the expected operation regimes / uncertainty
Consider the planned availability rate and unit importance
Identify and track local weak points for accelerated aging
Optimize maintenance strategy, e.g. outage intervals [48]
Restructure offline inspections and online test policy
Define online monitoring systems for early warning
Plan the strategic spare parts policy
Consider modernization, e.g. load dependent cooling
Decide refurbishment / replacement of critical components.
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TR-69 — Grid Code Impacts on Generator Standards
Qualifying in-service turbine generators for the new conditions stipulated by grid codes is
more difficult (sometimes even impossible) than doing so on a new unit design.
Operating old units in new grid code conditions can jeopardize the generators and affect
their remaining lifetime. The risks should be deeply assessed and suitable measures
should be implemented. In some cases, such adaptations cannot be possible without
major refurbishment (if worthwhile) or even equipment replacement.
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TR-69 — Grid Code Impacts on Generator Standards
4.
OVERALL CONCLUSIONS AND RECOMMENDATIONS
The body of this report includes information on various technical aspects which need to be
considered for operation of synchronous generators. This section of the report presents the
overall conclusions and recommendations of the task force organized into three groups.
The first set of conclusions are suggestions for future edits of grid codes. The second set
of conclusions recommends updates to IEEE and international standards for generators.
Finally, the report concludes with a summary of factors which are important to all those
involved with synchronous generators operating in or being planned for today’s rapidly
evolving electrical power systems worldwide.
Note that these conclusions and recommendations are listed with only brief details in this
section of the report with further supporting information and justifications being provided
in the body of the report.
4.1
Recommendations: Suggestions for Grid Codes
The task force recommends that the following should be considered when making future
updates to grid codes:
4.1.1 Capability Envelope
i.
Harmonize voltage and frequency ranges with other grid codes and
international standards and define voltage and power factor ranges relative to
generator terminals wherever possible.
ii.
Add definitions for operating conditions and requirements for duration and
frequency of occurrence of excursions from standard requirements.
iii.
Permit the use of on load tap changers (OLTCs) where appropriate to support
system voltage and reactive power requirements.
iv.
Harmonize short circuit ratio (SCR) requirements across grid codes worldwide
where power systems have similar grid topology.
v.
Include flexibility to permit lower generator SCR if studies show no significant
benefit in terms of grid stability
4.1.2 System Faults
i.
Include at least the option to conduct appropriate studies or investigations to
determine details aspects of the design of the power plant.
ii.
Include a recognition that fault ride through (FRT) capability depends upon
additional factors and not just the synchronous generator itself.
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TR-69 — Grid Code Impacts on Generator Standards
iii.
Create mechanisms to assign the ability to maintain maximum power output in
case of frequency deviations.
4.1.3 Excitation Systems
i.
Permit site-specific studies to determine suitable parameters such as excitation
speed of response and ceiling and which may reveal cost-effective options that
maintain system security.
ii.
Include mechanisms and procedures to resolve problematic interactions with
turbine-rotor torsional modes or other prime mover dynamics
iii.
Include additional information to define requirements for pre-commissioning
engineering studies, documentation and on site testing requirements for
excitation systems
4.2
Recommendations: Suggestions for Standards
The task force recommends that the following should be considered when making future
updates to IEEE and international standards such as IEEE standards C50.12 [75], C50.13,
1547 and the IEC 60034 series. The task force enthusiastically supports efforts to
harmonize as far as possible IEEE and IEC standards:
4.2.1 Capability Envelope
i.
Accept short-term overheating during defined short term voltage and frequency
excursions.
ii.
Include an evaluation guide for life time consumption resulting from voltage /
frequency excursions.
iii.
Consider extending the allowed voltage variation from ±5% to ±7.5%
4.2.2 System Faults
i.
Include design guidelines related to fulfilling fault ride through (FRT)
requirements.
ii.
Add informative text to explain that wider scope considerations are needed to
comply with system FRT requirements including pre-fault conditions, turbine
inertia, fault location etc.
iii.
Add guidelines on auto re-closing to IEC60034. (Unit studies are already in
C50.13)
iv.
Add guidelines on RoCoF to IEC60034 and IEEE C50.13.
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4.2.3 Excitation Systems
i.
Add information to the IEEE421 series standards to define requirements for
pre-commissioning engineering studies, documentation and on site testing
requirements.
ii.
Enhance existing standards for generators, excitation and protection systems to
include optionally expanded value ranges and allowed times for stator and rotor
current.
4.2.4 Operational Flexibility
4.3
i.
Add definitions for duty cycles (starts and stops and MW-MVAr load cycles).
ii.
Consider including weighted average parameters, such as weighted average
efficiency
Recommendations: Awareness for Stakeholders
In addition to making recommendations for future updates to grid codes and generator
standards the task force presents here a number of important points which are likely to be
very useful to those whose work involves synchronous generators operating or planned for
operation in power systems around the world which are undergoing a transition to include
very substantially increased renewable generation.
4.3.1 Capability Envelope
Owners and operators should make realistic plans and expectations regarding the
achievable maximum lagging power factor when system voltage is high and maximum
leading power factor when system voltage is low, particularly when on load tap changers
are not available.
4.3.2 System Faults
All stakeholders should consider fault ride through (FRT) withstand capability and
understand that compliance is also a power system and turbine issue and not simply a
generator issue alone.
The grid configuration, the short-circuit level at the connection point, as well as the
operating point of the plant, all have major impact on the FRT withstand capability of the
plant.
The ability of the power plant auxiliary systems to sustain critical processes also contribute
to the ability of the power plant to ride-through grid related system faults.
Project management should plan for studies or investigations to include FRT compliance
before finalizing the design of the power plant.
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TR-69 — Grid Code Impacts on Generator Standards
It is important to be aware that it may not be possible to use standard generator designs
when there is a requirement to comply with diverse voltage-time curves in grid codes.
With increasingly frequent reports of existing generators experiencing extreme system
faults as a result of the energy transition it is important that owners and operators carefully
undertake post fault reviews of equipment after such events. It is very likely that damage,
which may be latent, will follow a multiple FRT event, an extreme excitation forcing event
or an event where output voltage is maintained during a severe underfrequency. Therefore
such events should always be followed by rigorous inspection.
With FRT events becoming more probable it makes sense for owners to consider
installation of synch-check relay supervision for auto re-closing systems.
High RoCoF withstand capability requirements shall need in-depth investigations to
determine the impact not only on the synchronous machine but all the power plant
equipment (control systems, turbines, transformers, auxiliary systems etc.).
Similarly, when line auto-reclosing systems are installed near a power plant, the impact of
such systems on the power plant should be fully investigated to determine the impact on
the mechanical integrity of the turbine-generator shaft-line. If high risks of damage to the
shaft-line have been identified, mitigation means must be implemented to ensure the safety
of plant personnel.
4.3.3 Excitation Systems
When writing requests for quotations (RFQs) wording such as “the equipment shall meet
all applicable local and national requirements” should be avoided as this is not possible for
the equipment vendor alone. Rather, requirements need to be explicitly stated based upon
the technical and regulatory needs.
When referring to requirements it is important to understand that some performance
requirements either inherently require or inherently prohibit the use of certain technical
solutions. For some new build projects, depending upon the project timetable, such
requirements may be adjusted according to the technical solution preferred by the parties
involved. For example, speed of response is specified as a range rather than an absolute
requirement in the UK grid code with the absolute value being specified after a system
study as part of the bilateral connection agreement.
Grid codes should allow site-specific studies which may reveal cost-effective options
which maintain system security.
It is always important to specify and to be clear about the conditions under which excitation
ceiling, ceiling time and response time apply.
It is always important to ensure that division of responsibilities for coordination of AVR,
PSS, excitation limiters and protection settings and required stability studies are well
communicated and understood to ensure stress free project delivery. A multi-disciplinary
team is usually required to combine the diverse requirements.
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TR-69 — Grid Code Impacts on Generator Standards
Stakeholders should be alert to conflicts between generator and protection standards and
some grid codes which require higher levels of stator and rotor current than equipment
design standards allow.
Grid codes should include the necessary test conditions and acceptance criteria for each
requirement, including confirmation of compliance for unusual system conditions not
normally feasible to directly confirm by tests.
4.3.4 Operation of Existing Generators and the Need for Operational
Flexibility
The task force recommends those responsible for the operation of existing generators to
complete detailed technical and economic studies to ensure that generators are able to
withstand the new operating conditions and to assess any needs for lifetime extension.
It is important to keep in mind that qualifying of in-service turbine generators for new
operating conditions can be very difficult (sometimes even impossible) when compared
with a new unit design and operation of old units in new grid code conditions can
significantly affect residual lifetime. The associated risks should be carefully assessed and
suitable measures implemented where necessary. In some cases, such measures are not
possible without major refurbishment or even equipment replacement New developments
in on line monitoring can be used to provide early indications of impending failures or
consumption of residual lifetime so that contingency actions may be implemented in a
coordinated manner.
4.3.5 Call to Action
The task force encourages readers to take note of the recommendations in this report
regarding grid codes and consider carefully the highlighted consequences of the energy
transition and new grid code requirements for both new and existing synchronous
generators.
The task force particularly encourages industry consultations to ensure design standards
and grid code requirements are harmonized. These consultations should also strive to
ensure that the efficiency, reliability and economic targets of all stakeholders can be
achieved. Additionally, given the fluid nature of the recent and ongoing energy transition
towards large-scale integration of renewable energy sources, it is expected that further
review and refinement of the findings and recommendations included in this report will
become necessary.
Having completed this IEEE report the task force members plan to direct their immediate
efforts to updating of the related IEEE standards and contributing to the development of
other new and updated standards to support the energy transition.
Readers with suitable competencies and experience are encouraged to contribute to future
work of this task force and the IEEE Electrical Machinery Committee standards working
groups.
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TR-69 — Grid Code Impacts on Generator Standards
5.
ACKNOWLEDGEMENTS
Figures appearing in this report were provided by the organizations listed below and the
task force gratefully acknowledges their contributions:
ABB Switzerland Ltd.
Fig. 40
Brush Electrical Machines Ltd.
Fig. 32, Fig. 33, Fig. 34, Fig. 35, Fig. 37
General Electric Company Inc.
Fig. 8, Fig. 9, Fig. 20, Fig. 27
Kestrel Power Engineering Ltd.
Fig. 36, Fig. 38, Fig. 39, Fig. 41, Fig. 42
Siemens A.G.
Fig. 43, Fig. 45, Fig. 46, Fig. 47, Fig. 48
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TR-69 — Grid Code Impacts on Generator Standards
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82