This article describes the main differences of characteristics between an inverter based generator and a synchronous generator.
As interconnection requirements (grid codes) evolve, inverter-based generator (IBG) functionalities and their behaviour will approach that of large capacity synchronous generators. The term, “synchronous generator” only denotes large capacity synchronous generators and which it is assumed will be replaced with the IBGs where there is a high level of penetration of renewables. The main difference of characteristics and behaviour between the IBG and the conventional synchronous generator are summarized as follows:
1) Rotating Mass / Inertia:
Inverters do not have a rotating mass component; i.e. there is no inherent inertia. The prime mover behind the inverter might have the inertia, but its “usage” has to be achieved via the inverter controls and the inverter size because all IBGs are limited in terms of maximum current through the power electronics devices, as well as maximum voltage. To use the real available inertia, if any, of the “prime mover”, a significant oversize of the inverter generator or room to increase output may be necessary because the available energy reserve in IBGs is very limited and thus the inertial response of IBGs is eventually withdrawn. Moreover, synthetic inertia cannot be considered completely equivalent to the inertia provided by conventional synchronous generators which are directly connected to the grid as measuring devices and controls introduce delays to the synthetic inertia reaction to events in the grid. Although the fast frequency response has been commercially available, the synthetic inertia is still carefully evaluated and not in practical use.
One of the promising schemes for representing the synthetic inertia captures the Rate of Change of Frequency (ROCOF) and increases or decreases the IBG output so that the frequency change is mitigated. This concept enables the reduction of the mismatch between the mechanical output and the electrical output when ROCOF is not zero. When a generator tripping is considered as an example, the power output of remaining synchronous generators shows the stepwise increase right when the generator tripping occurs as per below figure:
It should be noted that the ROCOF is zero at the moment the generator trip occurs because the system frequency is the pre-disturbance/initial frequency at the moment. Even if the primary frequency response can be ideally emulated in IBGs, the immediate increase in the IBG output cannot be observed without the inertia effect (See pink dotted line of PG2). Such stepwise increase in the synchronous generator output will definitely alleviate the frequency drop.
Synthetic inertia cannot achieve this behaviour mainly due to delay in ROCOF measurement, filtering and control. Therefore, the synthetic inertia concept of modifying the controls dependent on the measured ROCOF cannot be currently considered completely equivalent to the inertia provided by conventional synchronous generators.
2) Fault Current Contribution
Inverters predominately lack inductive characteristics that are associated with rotating machines because it is controlled by power electronic equipment and not by electrical machines. The classical short circuit current contribution expected from synchronous machines does not apply (as caused by the law of constant flux in rotating machines). Instead, a short circuit contribution is possible by means of inverter control. However, this contribution is typically limited to slightly above 1 p.u. current (limited overload capability of a semiconductor power electronics device), provided that all the active power supplied to the network is reduced to zero and all the current which is able to flow through the power electronics devices without damaging them is turned into reactive power.
Of course, a certain oversize of IBGs would help to reduce also this gap with respect to traditional synchronous generators. If the voltage at the PCC during a fault is very low, the phase angle of the current injected by the inverter may be ill defined, which means, the expected fault current is unlikely to be provided no matter how oversized IBGs are applied.
Therefore, many grid codes exempt IBGs from providing reactive current and allow to cease the current injection when the residual voltage is below a threshold value, such as 20% of rated voltage. It is noted that the limited infeed of the fault current is revealed when the PCC is located near the fault point only. In other words, if the voltage at the PCC during a fault is not too low, the substantial infeed of the fault current may be expected regardless of the electrical distance between the PCC and the fault point.
3) Control Response Capability
The control response of inverters can be extremely fast (certainly faster than a rated frequency cycle). This offers the opportunity to design the inverter response to be quite flexible. Thereby, both the needs of distribution and transmission system can be taken into account, even implementing different behaviours/responses in the inverter generators according to external signals/commands, voltage/frequency measurements, presence of local fault or perturbation on transmission system, etc. Conversely, inadequate design of controls may result in abnormal behaviours affecting the power system, both in normal operation and unintentional islanding e.g. because of a too fast response by the control loops to even small voltage and frequency variations
4) Constant Voltage Source
The voltage induced in the windings of a synchronous generator (also known as internal induced voltage) is typically larger than the grid voltage. Moreover, this internal induced voltage is independently regulated from the grid voltage. It will cause increased current injection as the grid voltage sags and hence typically contributes positively to network stability. IBGs do not have such an inherent internal voltage source. The current that can be provided to the grid during a voltage sag is dominated by the IBG control behaviour and typically limited to 1 p.u. It should be noted that the operation mode of IBGs typically cannot change without stopping the inverter, although the IBGs also have the ability to create voltage through U-F mode (also called isolated operation mode) instead of P-Q mode.3
5) Transmission-Level Voltage Support
Large capacity synchronous generators generally operate in AVR mode. That means such generators have an ability to regulate the terminal voltage and the system voltage in HV network (e.g. typically equal to or higher than 200 kV) near the generator bus. Small capacity synchronous generators generally operate with Automatic Q Regulator (AQR) or Automatic Power Factor Regulator (APFR) mode (this means they do not regulate the terminal voltage but the reactive power or the power factor coming from the terminals). That is because the reactive power injection of these units is limited, thus they do not have a capability for changing the terminal voltage and regulating the system voltage. The IBGs are generally assumed to operate with a unity power factor. That means most of the IBGs operate with AQR mode, the power factor of which is one. Thus, actual voltage control for transmission-level voltage support cannot be expected or achieved. However large-scale IBGs can support the transmission-level voltage with the aid of other external voltage controls such as reactive power compensator and/or Static Var Compensator (SVC). The IBGs themselves can change the reactive power output through the oversized inverter and/or through the reduction of active power output. Modern grid codes such as VDE4120 in Germany have required the voltage control at the IBG’s PCC.
6) Synchronization (Torque) Capability
The synchronous generators have the synchronizing torque capability which is a very important factor for angle stability. The synchronizing torque index, Kij is proportional to the internal voltage of the synchronous generator and the equivalent synchronous generators and/or the angle difference between the synchronous generators and the equivalent synchronous generator.
Such generators can automatically change their active power output so as to mitigate the change in the angle difference. It is noted that this capability does not denote the ability which tells how the IBGs in general capture the voltage angle through a Phase Locked Loop (PLL) algorithm in order to output the active power and reactive power in a correct phasor form. This capability reacts not to the voltage angle itself but the angle difference between two different points in order to contain such angle difference within 180 degrees. This ability is one of the important contributions especially for rotor angle stability.
It should be emphasized that this capability is not literally required for IBGs because they have no rotor-angle stability issue. On the other hand, the IBGs might be required to have the synchronizing torque capability in the future although IBGs do not need to be synchronized. In such a case, this is not easy to be achieved because the communication infrastructure for measuring the aforementioned angle difference is basically required. Even such angle difference is assumed to be measured nearly in real time, tremendous number of measurements are required in wide area, because the equivalent synchronous generator to be measured for calculating the angle difference is not always the same and significantly changes especially when a synchronous generator in a network of equivalent synchronous generators is disconnected (See Figure 2.2):
7) Loss of Synchronism
Synchronous generators cannot avoid loss of synchronism when angle stability cannot be maintained, while the IBGs do not have a rotor angle and keep synchronism inherently. As mentioned earlier, IBGs in general capture the voltage angle through a PLL algorithm in order to output the active power and reactive power in a correct phasor form. These characteristics can be also treated as a sort of synchronization capability. IBGs are required to be synchronised with the AC grid by PLL. The characteristics of these PLL algorithms, in particular during system disturbances, might impact the inverter response. It is noted that the IBGs might also lose synchronism i.e. might be disconnected due to the significant voltage dip, but do not have transient stability problem.
8) Damping Torque Capability (Power Oscillation Damping: POD)
Oscillations can be damped when extra power is injected into the system in phase with the rotor speed deviation, which is instantaneously decelerated, and/or when extra power is consumed in the system, which is instantaneously accelerated. In real power systems, the damping power is obtained by the modulation of load or generation for a period of time, typically in the range of 5 to 10 seconds. This damping torque can be achieved in two ways.
Inherently, synchronous generators have short-circuited damper, or amortisseur windings, to help damp mechanical oscillations of the rotor if the rotor speed deviates from synchronous speed, the flux will not be stationary with respect to the rotor and currents will be induced in the damper windings. According to Lenz’s law, these currents will oppose the flux change that has produced them and so help restore synchronous speed and damp the rotor oscillations. Supplementary controls, called power system stabilizers (PSS), can be used to further enhance the damping of local and inter-area modes of rotor oscillation among generators.
In the case of IBGs, the modulation of active power dampens the oscillation directly, whereas modulation of reactive power dampens indirectly by modulation of the system voltage and therefore by modulation of the voltage dependent loads. The way this modulation achieves mitigation of oscillations is by means of active and reactive power injection, which can be implemented in a POD controller. The control scheme of the active power injection is the same as the PSS which is often applied to large capacity synchronous generators. For example, an additional control loop could be used to modulate the voltage at the PCC and to achieve the damping effect via the connected load with the load voltage characteristics.
9) Frequency Control Capability (primary, secondary and tertiary)
Turbines directly linked to synchronous generators can have primary, secondary and tertiary frequency control capabilities. This capability strongly depends on the prime mover characteristics, not the generator. In order to emulate those capabilities, the IBGs need to increase or decrease their active power output. However, the energy sources connected to the grid via inverters are in the majority of cases not controlled. IBGs can rather easily decrease their active power output but it is not easy for them to increase their active power output. An option is to reduce their active power reference intentionally at steady state in order to ensure an adequate upper margin or headroom. This has obvious economic implications, particularly for RESs where curtailing the IBG means essentially lost opportunity costs that cannot be recovered since the energy source is variable. Another option is to marry an energy storage option with the IBGs. It should be noted that this could cause additional burden to the IBG owners. Also, it has to be considered that even for traditional power plants with synchronous generators keeping additional generation margins available for regulation represents an additional cost.
10) Limited Frequency Sensitive Mode
In the case of significant frequency rise, power plants need to decrease their outputs. This emergency corrective action is called “Limited Frequency Sensitive Mode – over frequency” It is important to note that any kind of generator can operate in the limited frequency sensitivity mode, but their prime movers may not be able to provide this operating mode. (For example, in the case of gas turbine power plants, the sudden decrease of fuel input will increase the air-fuel rate and could cause the undesired /unintentional flame-out of the combustion system. This capability strongly depends on the prime mover characteristics, not the generator. For many IBGs, this is not a limitation. For example, PV can easily reduce its output if the inverter is controlled according to this mode.
11) FRT Capability
Synchronous generators are required to withstand without failure a short circuit of any kind at its terminals by IEC Standards (IEC 60034-3 Clause 4.16). On the other hand, the prime movers do not always have the fault ride-through capability. While most of the representative prime movers of large-scale hydro power plants, coal-fired power plants and nuclear power plants have such capability, some prime movers of medium-scale thermal power plants have a shear pin embedded in the rotating shaft and designed to break during severe voltage dip (when the shear pin breaks during severe voltage dip, the power plant is tripped).
To date, distributed IBG typically do not ride through severe three phase faults because the voltage phase angle could not be detected when the line voltage is very low, e.g. less than 30% because the magnetic contactor which is placed between the inverter and the grid will open due to the loss of its excitation of the magnetic coil. It is noted that this is the issue of the contactor and not of the inverter. New techniques such as higher resolution frequency calculation, and the use of the off-delay release type magnetic contactor or the UPS can now achieve the fault ride-through capability
12) Reactive Power Support
(a) V-Q control during steady-state
The rated power factor of the synchronous generators is generally in the range of 0.80 – 0.95, with the higher value being typical of modern units. The rated power factor for distributed IBGs is not often provided, which means the rated power factor is assumed to be unity
Distribution-connected PVs are still operated at unity power factor over their entire active power output range in many countries. Most of these inverters are not sized to provide any reactive current at full output. In order to provide reactive power support at full output, larger inverters will be required. On the other hand, system operators usually require that IBGs include reactive power control at the PCC. In addition, this reactive power control to be independently activated by such multiple alternatives as voltage regulation, reactive power regulation or power factor regulation.
(b) Reactive current control during network incidents
A synchronous generator can dynamically support the reactive power output from the moment when the system fault occurs thus providing an immediate/instant increase of reactive power output. In contrast, it cannot be guaranteed that the IBG can increase the reactive power output from the moment when the fault occurs to mitigate the voltage drop mainly because the detection time of the voltage magnitude of the IBG cannot physically be instantaneous. The IBG enables an increase in the reactive power output with some delay during the fault by decreasing the active power output within the rated current. Therefore, no matter how quickly the IBG is able to control voltage and current, the IBG cannot show the same immediate/instant increase of the reactive power support provided by the synchronous generator. In addition, a synchronous generator allows a negative sequence current to flow, whereas the IBG is often designed to block negative sequence currents. In the future a TSO may require that the IBG provides a negative sequence current in case of unsymmetrical faults mainly to ensure sufficient voltage recovery for all three phases
13) Harmonic Emission
Inverters may produce non-sinusoidal currents that can be described and quantified as harmonic emission in frequency domain. The harmonic emissions need to be assessed and controlled before the connection is permitted. The IEC has standards of harmonic emissions and some countries impose their own limits for connection of nonlinear appliances to the grid. Harmonic currents emitted by synchronous generators (airgap flux harmonics, slot harmonics, etc.) are usually negligible. The harmonic current emission of IBGs depends on the following; type of technology used, control strategy of the DC/AC-inverter, existence of high- or low-frequency coupling transformer and the harmonic voltages prevailing in the AC-power system.
14) Harmonic Voltage Reduction
Since the effective impedance of synchronous generators for low order harmonics is based on the small sub-transient reactance, synchronous generators provide a rather low impedance path for harmonic currents and thus tend to reduce harmonic voltages. All voltage source converters absorb harmonics because inverters can act as an impedance using the voltage source converter technologies
15) Black Start
It is the ability of the power system to restart itself after a full or partial system black out. Most conventional generators are designed to require an electrical supply from the power system to start up. Normally this is provided from the transmission or distribution system, however under black start this supply is not available. Therefore, to restart the system it is required to some power stations have their own auxiliary supplies to they can restart themselves. These power stations can then be used to restart other power stations and thus the whole system can be restarted. Traditionally black start capability relies on large transmission-connected synchronous generators. Over the coming years the trend of reduction in the number of these plants is expected to continue leading to fewer traditional black start providers being available. For an IBG the ability of the technology to achieve black start is more limited under extreme network conditions due to factors such less inertia, less overload capacity to provide inrush current for energization and the use of PLL technology.
