Concerning Short-Circuit Current Contribution Challenges of Large-Scale Full-Converter Based Wind Power Plants

The calculation of short-circuit current contributions from full-converter based type IV wind turbines and other inverter-based power plants are often simplified. They are represented as simple fixed current sources for the steady-state stage of the fault during short-circuit evaluations. As wind power penetration increases, it becomes increasingly important to factor the details of short-circuit contribution from such inverter-based power plants for long-term planning as well as equipment and protection system design. The challenge lies in the fact that this type of inverter-based power plants is fully connected through power electronic devices, and their short-circuit contributions cannot be easily represented and calculated based on traditional physical laws developed for synchronous generators. This paper addresses the main challenges and limitations of the current accepted practices in the industry. The challenges are discussed for all three stages during a fault referring to the stages of more traditional power plants, namely sub-transient, transient and steady-state. An electromagnetic transient (EMT) model validated through field tests on a full-scale prototype wind turbine was used to simulate over 20,000 scenarios and examine the three stages in detail. Results show that during the sub-transient stage, in the first milliseconds of the fault, the converter exhibits a so-called quasi-voltage source behavior with high currents limited by transient hardware limitations and high negative sequence current injection for unbalanced faults, regardless of the current priority chosen. During the transient stage, the converter starts transitioning to a grid code/voltage-dependent current source until reaching the steady-state stage of the fault. The paper also includes a theoretical analysis, a comparison with the conventional ac-dc fault representation, and thorough time-domain and statistical analyses of the relevant variables during a short-circuit. Finally, it outlines future challenges and identifies areas of improvement for enhancing the modeling of fault currents in Type IV wind turbine generators.


I. INTRODUCTION
As a result of the ambitious targets set by society and governments around the world, wind, solar, HVDC and other inverter-based resources (IBRs) are growing rapidly in all parts of the world. Current outlooks from DNV and the The associate editor coordinating the review of this manuscript and approving it for publication was Pierluigi Siano .
International Energy Agency estimate that by 2050 wind and solar generation may account for almost 70 % of the total energy-generation worldwide, where in 4 of the 5 continents onshore and offshore wind generation will account for 50% of the generation [1], [2].
The need for accurate short-circuit current (SCC) estimation/calculation for the different equipment in the system has been historically proven as large blackouts and equipment damage or loss have occurred due to incorrect design of equipment or maloperation of protection relays. Thus far, the contribution from Inverter-Bases Resources (IBRs), specially the ones with full converter, have been either neglected or simplified, since many grid connection codes and standards such as IEC 60909-0 Ed. 2 allow neglecting of such power stations if their contributions are not higher than 5 % of the total short-circuit current without these power stations [3]. Even though the situation will change in the future, still to these days, many of the countries in Europe and especially in other continents of the world (e.g. Americas or Asia) are still mostly dominated by synchronous generator-based generation. As a result, during more than 100 years of operation of these machines, the industry has established very robust metrics for different types of stability and faults based on defined physical laws and boundaries [4], [5]. However, due to the current energy transition and ramping-up of IBR penetration, the industry is acknowledging the effects of these devices in several traditional definitions and slowly considering more these effects for different aspects [6].
According to standards and guidelines, the maximum short-circuit current contribution is used to define the rating of equipment regarding mechanical and thermal stresses while the minimum short-circuit current must be calculated to define the selection of system protection [3], [5]. This widely accepted statement may not although fully cover all protections as impedance-based and other types of protection also use phase angles and sequence components based algorithms [7]. As the connection of IBRs to the system is growing exponentially, specially large-scale offshore wind power plants (WPPs) and HVDC, plant/system-level design of equipment and protection studies will start requiring more accurate representation of the short-circuit injection of these resources as their characteristics during faults are inherently different than conventional generation.
Research started to be more focused on the short-circuit contribution of IBRs back in late 2000s, where the shortcircuit contribution of the different types of wind turbines was explored in [8], [9], and [10] while an overall approach for IBRs was studied in [11]. The conception that Type IV Wind Turbine Generators (WTGs) and other full converter connected generate a fixed current between 110 -120 % was common in this early literature. On the other hand, some work with more realistic Electromagnetic Transient (EMT) simulations could already identify that currents during transients could go above the maximum allowed current during steady-state [12]. In [13], requirements for fault ride-through (FRT) were discussed along with definitions of stages during the fault for a synchronous generator that could aid on the definition of requirements for wind turbines and other IBRs.
The research and efforts to better account for contribution of IBRs culminated in the update of different standards and guidelines in the more recent years like the IEC 60909 -Short-circuit currents in three-phase a.c. systems -Part 0: Calculation of currents [3], where Type IV Wind Turbines and Solar PV are usually modelled as a fixed current source. Recent work based on the updated standards was performed for Type III Doubly-Fed Induction Generator Wind Turbines where a methodology was developed to estimate the parameters and calculate the short-current contribution of these generators [14]. When it comes to full-converter connected generation, other works based on standards were also performed to calculate the SCC contribution with general assumptions for modelling these resources as static current sources [15], [16]. An overall comparison among the different standards was published in [17].
Aside from the standard-related works, a phasor-model based approach was used in [18] to model the SCC contribution at steady-state of Type IV wind turbines as a voltage dependent current source with an algorithm that can achieve similar results as an EMT simulation. A review of the short-circuit contribution under unbalanced faults with different control strategies was performed in [19]. Finally, a systematic review of the short-circuit characteristics of IBRs was done recently [20].
Thus far, from the knowledge of the authors, there is no holistic work that has studied the SCC of an large-scale industrial full-converter Type IV wind turbine throughout all the transient and steady stages using a validated EMT model. This paper contributes in four different aspects: 1) identifies the main characteristics about the different stages of the short-circuit in such a wind turbine; 2) performs a theoretical analysis and comparison with the classical ac-dc fault representation; 3) carries out thorough time-domain and statistical analyses on the different variables during a shortcircuit; 4) draws future challenges and work that need to be done for better modelling of fault currents in Type IV WTGs. In Section II, an overview of the current state of short-circuit current calculation from different views is initially given, including types of models, standards, grid codes and TSOs. Section III dives into the control topology utilized and explanation of the fault ride-through control specifically. It also explains how the wind turbine systems are modelled in an EMT simulation tool and validated against the real turbine response using a full scale prototype on site. Based on the validated model, the actual contribution from the Type IV wind turbine is explored through more than 20,000 simulations of different Fault Ride-Through (FRT) cases. These cases are presented in p.u, where many of the conclusions can be applicable to other similar converter and/or control topologies utilized in the industry.
A theoretical analysis is presented in Section IV, where three different stages of the fault are defined: sub-transient, transient, and steady-state. During the sub-transient and transient stages, the Type IV wind turbine with a grid following control acts for a brief period as a quasi voltage source and then starts transitioning to the well known current source behaviors. For this brief period, current values can go up to 2 p.u. (for the equipment studied) and are limited by embedded capabilities to protect the converter hardware from destructive transient peak currents and also by inherently electrical constraints at both the turbine and system levels. During these two stages, phasor analysis and the inspection of the sequence components also support the arguments for a quasi voltage source behavior. During the steady-state stage of the fault, an extensive sensitivity analysis was also performed and a few details often missed by other studies were identified such as the effects of the prevailing voltage, system topology during the fault, converter current nominal capabilities and other aspects.
Further considerations and selected simulations results are presented in Section V. Results show that the different stages are highly influenced by the non-linearities of the proprietary controls utilized, the grid topology, fault conditions, grid code, and pre-fault operating points. Therefore, it is difficult to formulate mathematical co-relations that satisfy the behaviors and a statistical analysis is performed instead. Due to the complexity of analyzing all the simulation results, in Section VI a novel statistical methodology based on multiple regression analysis (MRA) is proposed and used. Results from the method also corroborate with the previously seen time-domain results. Finally, overall discussions and future work are presented in Section VII on the possible solutions involving better modelling for current short-circuit contribution, EMT modelling, and data-driven methodologies.

II. SHORT-CIRCUIT CURRENT CALCULATION: CURRENT STATE
As discussed earlier, SCC calculation has been a very important part of several design decisions in power systems. Below an overview of the current state of SCC is given involving standards, guidelines, different types of tools and TSO's point of view.

A. STANDARDS AND GUIDELINES
Currently, several standards explain how short-circuit current and analysis can be done in power systems for different voltage levels and different equipment, such as IEC 60909, IEEE 141/IEEE 551/ANSI C37, VDE 0102/0103, G74, IEC 61363, ANSI/IEEE 946, among others. In particular, the IEC 60909 -Short-circuit currents in three-phase a.c. systems -Part 0: Calculation of currents [3], was first established in 2001, with the intention of providing methods for calculating the currents during short-circuits in three-phase a.c. systems. Driven by the large increase of converter-interfaced power units, the IEC 60909-0 received a second edition in 2016 where information regarding different IBRs was included. Since then, several research articles have been published based on the revised standard [14], [15], [16].
When it comes to full converter connected wind turbines, IEC 60909-0 Ed2 stipulates that the current contribution can be assumed as a current source with an infinite internal parallel impedance as seen in Figure (1), in a way that the equipment will always deliver a fixed inductive current I sc and the RMS peak current I peak into the system, based on the  Equations (1) and (2) below: (1) where the multiplying factor k is supplied by the manufacturer and it is often referred to the additional capability above the nominal current at which the converter can deliver. The additional current capacity is usually around 10-15 % above the nominal but can go up to 50 % for some specific turbines.
The assumption that this value is the maximum current capacity of the converter may not always hold true, since some designs may allow room to operate at higher current values. However, in an effort to harmonize the current contribution from IBRs, it has been standardized that these resources should supply a maximum of 110-115 % during faults. Additionally, a few considerations for unbalanced faults are made in IEC 60909-1 Ed2 for the negative-sequence impedance depending on the design and control strategies.

B. TYPES OF MODELS AVAILABLE
In order to simulate and evaluate the effects of short-circuits, simulation models with different complexity levels can be employed. These models can in theory inherit different levels of accuracy and computational burden as shown in Figure (2). The complexity and accuracy are trade-offs that often are present in the model selection. Below, a short explanation on each of these simulation models is given.

1) SHORT-CIRCUIT ANALYSIS TOOLS
These tools are usually the simplest type of simulation tool used for studying the short-circuit contribution of the different generation types in a simulated system. They VOLUME 11, 2023 are mainly developed following guidelines and standards. In general, they can model the sub-transient, transient and steady-state stages of the short-circuit currents from synchronous generators and to some degree from Type III wind turbines [14], [17]. However, the same is not true for full-converter connected power generation systems such as solar PV and type IV wind turbines. These assets are recommended to be modelled in the simplest way possible as static current sources. This type of models can vary on complexity level, ranging from the most simple short-circuit calculation without computing specific operating points to the more complex representations where certain operating points pre-fault can be computed to better calculate the short-circuit current contribution from each generator in the system [21], [22].

2) ROOT MEAN SQUARE SIMULATION TOOLS WITH REDUCED-ORDER CONTROLS
Root mean square (RMS) simulations use symmetrical component analysis to represent the system during a short-circuit event. It is based on the assumption that the system is operating in a steady-state or quasi steady-state, and that the voltage and current waveforms are sinusoidal. This type of analysis is best suited for analyzing quasi-steady state conditions and are typically faster and less computationally intensive compared to EMT-based analysis. RMS simulations can be slower than short-circuit analysis tools. In addition, they need more detailed information about the converter controls. Such models usually incorporate a simplified control structure that can represent certain features and dynamics of IBRs. From a manufacturer point of view, RMS models are usually benchmarked against EMT models to ensure desired behavior using a reduced-order version of the original converter control implemented in the actual turbine.
The RMS tools mainly differ from the short-circuit analysis tools due to differences regarding the types of simulation that can be run. The challenges arise when fast dynamics are required to perform studies, either due to high frequency oscillations or more sensitive/weaker grid which are sensitive to individual wind turbine and collective wind power plant level controllers. Furthermore, during unbalanced faults, the transient behaviors might also present oscillatory torques due to the intrinsic control delays [23], [24]. These type of tools may not be able to fully represent the dynamic behaviors in very fast transients for sub-cycle protection studies or high frequency phenomena evaluation.

3) ELECTROMAGNETIC TRANSIENT (EMT) SIMULATION TOOLS
EMT-based short-circuit analysis uses electromagnetic transients simulation to represent the system during a shortcircuit event. It is based on the calculation of instantaneous voltages and currents and therefore can represent voltage and current waveforms that are not necessarily sinusoidal. This type of analysis can simulate a wide range of short-circuit events, including unsymmetrical and non-linear events. EMTbased short-circuit analysis typically provides detailed and accurate results than RMS-based analysis, but it is also more computationally intensive and time-consuming.
In an industrial setting, the full-order control source code is usually embedded in the form of a .dll (Dynamic Link Library) or another type of encrypted form in the commercially available offline EMT tools and can, therefore, represent the control with high accuracy.

C. SYSTEM OPERATORS' VIEW
Due to the increasing penetration of large-scale wind power plants and grids becoming IBR-dominated, the interest from TSO's in the matter of modelling the fault current contribution is growing. The European Network of Transmission System Operators for Electricity (ENTSO-E) has recently released a report where important considerations are made regarding which types of protection are mostly affected by the increasing penetration of new generating units with power electronics [25].
In the context of North America, the California Independent System Operator (ISO) [26] has recently started requiring manufacturers to supply different tables containing current magnitudes and angles per fault type and for a range of 0 to 0.9 p.u. of positive sequence residual voltage in three different stages of the fault (i.e. 1st cycle, 3rd cycle and 5th cycle). The intent is to use this table to validate simulation results. It will be shown later in this paper that this strategy cannot fully represent the actual converter response as the current in the initial stages depends on a large variety of factors.
According to [27], specially in small IBR dominated grids, microgrids or islanded operation, there is a tendency of needing more current during fault to distinguish fault current from inrush current of transformers and motors. It can be expected that better modelling and even higher fault currents of around 2 or 3 p.u will be necessary for fault detection and proper selectivity in future systems.
As Power Plants are significantly growing in size and spreading throughout the power systems, it becomes more important to develop better estimating techniques and understanding on the SCC contribution from the growing size of PPMs which soon may surpass 2GW of size [28].

III. FULL CONVERTER CONTROL SYSTEM AND MODELS
In order to verify the short-circuit characteristics of a type IV wind turbine, necessary buiding blocks of the model need to presented. In this section, definitions of the full-converter control system including the control type, fault ride-through considerations and the voltage dependent current at steady state will be presented.

A. GRID FOLLOWING CONTROL
In Figure (3) a simplified view of the grid following control used in the paper is shown. A phase-locked loop (PLL) is utilized to synchronize with the systems' frequency and provide the phase angle references for the abc-dq transformations. The outer voltage/power control loop receives the power and/or voltage references from the wind power plant (WPP) controller and calculates the reference currents in the dq-frame to be passed to the current control. The main inputs to the single wind turbine are power and voltage setpoints. During an FRT event, the FRT control will take over and define the dq-current references for the inner current control, based on the different pre-fault and during fault measurements as well as the specific grid code requirements.
The total current is then limited to the equipment's limitation and passed to the fast inner current control loop which produces the voltage references for the pulse-width modulator (PWM). The control can be either CSC (coupled sequence control) or DSC (decoupled sequence control) [18], [29]. In the case of this paper, the DSC topology is used.

B. FAULT RIDE THROUGH CONTROL
It is important to note that, while standards may present simplifications, the contribution of IBRs to short-circuits cannot always be reduced to a simple inductive fixed current source. The actual short-circuit current in various fault and operating scenarios can be impacted by multiple factors. The SCC contribution from an IBR is mainly driven by Fault Ride-Through (FRT) grid code requirements and factors such as prevailing voltage and current, k-factor and the reference voltage used for current calculation.
Fault Ride-Through, also called Under-voltage Ride-Through (UVRT), is the ability of an equipment or system to sustain a faulty condition. The voltage drops below a certain threshold indicated by V min−frt shown in Figure (4) where the profile for voltage in p.u against time in seconds according to ENTSO-E. While sustaining the fault, many grid codes request power stations to perform voltage support in the form of injecting reactive current.
In most recent grid codes, with the advent of decoupled sequence control (DSC) schemes [29], current priority for reactive current injection is usually equally given to positive and negative sequence during faults. The injection of negative sequence improves the restoration of voltage to balance and the performance of negative-sequence based protection algorithms [25], [30].
Equations (3) and (4) show an example of how the total reactive current I react,tot can be calculated. The proportional gain for voltage support defined by the grid codes and commonly called K factor is used, where one value for each sequence component is used i.e. K + factor and K − factor . Priority can also be given to active current during faults [31], but this priority is not considered in the paper.
The voltage V calc can be either the rated voltage or the prevailing pre-fault voltage and V + res,mes / V − res,mes are the measured positive and negative sequence residual voltage at the turbine terminals. The maximum reactive current I react,limit restricts the injection of reactive current to 1 p.u of the nominal turbine rating.
In case priority is given to only positive sequence current, Equation (3) can be defined: In case of priority to both positive and negative sequence reactive currents, Equation (4) is used: Injecting more than 1 p.u. of reactive current (up to the limit of 1.1 for example) is technically possible however not widely adopted as no room for active power is left and stresses on the generator side can be damaging specially throughout the lifetime of the WTG [32]. Therefore, considering that the maximum reactive current of 1 p.u. is being injected and a current limit I limit of 1.11 p.u., which is utilized across the paper, (5) shows the active current limit that can be supplied during a FRT event, when maximum reactive current is being injected: Authorized licensed use limited to the terms of the applicable license agreement with IEEE. Restrictions apply.
where I active,limit is the limit for active current that can be pushed during the fault when maximum reactive current is being injected. Naturally, this is not always the case as the active power also depends on the turbines capabilities, the pre-fault/available power during the moment of the fault and also the equivalent system connected between the turbine and the faulty point. For example, if the prevailing power reference and current available power so that I act,ref > I activeFRT = 0.48, but there is no or very little load/resistance between the WTG/WPP and the fault location, the actual active current flowing will be less than 0.48 p.u. A few conclusions can be taken from the described equations: • The magnitude and angle of the current at steady-state will not always be equal to Equation (1) as the current injected is dependent on the prevailing and retained voltages, k factor, fault conditions and manufacturer's design criteria to limit the maximum total, active and reactive currents.
• The angle of the total current injected at steady-state will not always be 90 • as a room for active current during the FRT is usually designed as described in (5).
• The SCC can change depending on the current priority (pos or neg&pos), specially for shallow faults where the residual voltage during the fault is high due to a high fault resistance or a distant location of the fault. This will be discussed more in detail later.

C. MODEL BASED ANALYSIS
In this section a detailed overview of the model used in the paper will be given, including the WTG model layout, model validation with field measurements and finally the full setup used for this paper.

1) WTG EMT MODEL DESCRIPTION
The industrial EMT model used in this paper is developed in PSCAD™ and contains the permanent magnet synchronous generator (PMSG) and a full size voltage source converter (VSC) also known as Type IV wind turbine. The modelled mechanical system of WTG consists of: • Aerodynamic model: Torque controller representing the power coefficient (C p ), Tip Speed Ratio (λ) and the pitch angle (β).
• Shaft model: Including inertia and damping of two mass rotor and generator. Furthermore, the electrical system of WTG consists of:  Finally, the control system includes -among others: • WTG level controller: Reduced-order with functionalities deemed necessary for EMT type simulations) • Converter controller: Responsible for controlling the generator and grid side converters as well as the DC link. Full-order actual control source code is embedded as a .dll (dynamic link library).
• Protection: Full-order with turbine and converter level protection.

2) MODEL VALIDATION
Prior to carrying out extensive simulations for general conclusions, the model described previously is validated against real site measurements for FRTs. Usually, hundreds of different conditions under varying grid code related parameters, fault type, Short-Circuit Ratio (SCR), retained voltage, power reference, voltage reference, and other operating conditions and parameters are evaluated according to different grid codes and standards such as the IEC 61400-21-1 [33]. The field setup can be seen in Figure (5) where the wind turbine generator (WTG), filter and transformer are connected to a test unit. The measurements are taken at the low voltage (MP1 -LV) and high voltage (MP2 -HV) sides of the transformer as well as the short-circuit point MP3 and grid side of the test unit MP4. The measurements on site are performed using a test unit, also called FRT container, that can safely emulate a fault from the turbine perspective while keeping the grid contribution reduced for safety reasons. The procedure then is to playback the results as an equivalent voltage source in the PSCAD environment in order to validate the models. Measured voltages at MP2 are played back in the model and the entities at MP1 are compared for validation.
Below, an example is shown of a 3 phase fault with 0.25 p.u of power reference and 1 p.u. of voltage reference where the measurements were taken at the LV MP1 side. The comparison is made between field measurements and PSCAD simulation results in in Figure (6). The three phase LV voltages are shown in the upper graph, while the three phase LV currents in RMS are plotted separately. It can be seen that the simulations in PSCAD are matching almost one to one with the field measurements, showing high accuracy of the models which are capable of representing the reality. This procedure is repeated for hundreds of different faults in order to fully validate the model.
Besides field testing, the industry is already advancing with component and subsystem testing and Hardware/Softwarein-the-loop real time solutions [35], [36], [37], [38]. It can be expected that the model validation procedures widely adopted nowadays may also change and become even more accurate and reliable.

3) SIMULATED MODEL SETUP
The model used to generate the results presented in this paper has been developed and validated as discussed in the previous sections where a traditional control in grid following mode is used as shown in Figure (3). A standard single-turbine system connected to a Thevenin system equivalent is used and the model is built in PSCAD TM with the actual control source code.
In all the plots the fault start time is re-calibrated to 1s to overlay the results from different simulations together, but the actual fault applied time varied between simulations for different reasons. In all simulation cases, the wind turbine model was let to initialize and reach steady-state before a fault was applied. More than 20,000 EMT simulations were performed with variations of the following parameters described in following Table (1). The wind turbine model is connected to a simplified grid represented by a voltage source behind a Thévenin impedance (Z th ) also represented in Figure (3). The Thévenin impedance used in the simulation can be calculated based on (6), while the resistance and reactance between the turbine high voltage terminals and the fault as well as the one between the voltage source and the fault are calculated based on (7). In these equations, four important values which are the short-circuit ratio (SCR), reactance over resistance ratio (X /R), fault location (F loc ) and retained voltage (V retain ) are used. F loc is defined by the distance in % of Z th between the turbine HV terminals and the fault point. That means if the F loc = 0% the fault happens in front of the HV terminals of the turbine transformer and if F loc = 100% the fault is located in front of the voltage source.
where the S base is defined as the nominal power of the WTG and V base is the nominal voltage at the HV terminals of the transformer. In order to calculate the retained voltage (V retain ) at the fault point, a reverse calculation to find the correct fault impedance is also made according to equation below.
Similar to the results in the previous validation section, all the measurements shown are taken at measurement point 1 (MP1) at the LV side of the WT transformer. As shown previously, the procedure for designing and validating such models is extensive in order to ensure the highest accuracy possible when performing the studies presented in the next sections.

IV. SCC CHARACTERISTICS OF FULL CONVERTER SYSTEM: THEORETICAL ANALYSIS
Thus far, the SCC characteristics of the full converter were mainly discussed based on the existing guidelines and grid VOLUME 11, 2023 codes for steady-state modelling. In this section, the SCC characteristics of full-converter based systems are discussed based on a theoretical analysis of the entire fault transients. Three stages are initially defined in a manner to simplify the understanding and approximate to the stages commonly discussed for traditional generators. However, at the end, it is also concluded that it is difficult and to an extent undesirable to approximate the SCC from a full converter based system to the one from traditional synchronous generators as the two behave fundamentally differently when exposed to a short-circuit. (7) shows the response of the wind turbine when subjected to a power system fault is shown. In a real-life converter, there will always be a delay between the fault inception and the converter control responding to the changes in feedback/demand and identifying the fault. This occurs due to control bandwidths, measurement, filtering and communication delays inherently embedded in the system. The simulated system validated against the real measurements is implemented with these features. For that reason, it is possible to demonstrate the three different stages for a Type IV wind turbine consisting of the sub-transient, transient and steady-state stages of a fault.

Figure
A phasor analysis of the system is used to better discuss these stages in detail. In this system, a single turbine is connected to a power grid. The network is shown in Figure 8 (a), where the wind turbine LV side voltage is represented by V lv ̸ δ v .
During the pre-fault stage, a situation is considered where the converter is exporting full active power and a small amount of reactive current to maintain the LV terminal voltage at 1.0 p.u as set by the voltage reference. In Figure 8 (b), the phasor diagram representing the steady state condition pre-fault is shown. A fault is now applied at a distance from the wind turbine with impedance Z wt . The fault location, voltage amplitude and angle of the retained voltage is given by V f ̸ δ f . In the event of a fault, the amplitude V f will reduce instantaneously.
At the initial sub-transient and transient stages, the wind turbine is ''decoupled'' from the grid voltage in case of three-phase bolted fault as the voltage V f will drop to 0. At this stage when the converter control including current control has not responded yet, the converter voltage V c ̸ δ c will remain unchanged. The current from the converter in this instance is driven by voltage V c ̸ δ c and the total impedance towards the fault Z wt ̸ δ z with X /R ≫ 1. Hence, a quasi voltage source behavior can be expected as this stage. The current from the converter must convert from majority active to majority reactive export and for that reason the LV side voltage angle δ v will increase towards δ c . This implies that the LV voltage angle is deviating away from the PLL angle. Consequently, the feedback currents will start to deviate from their respective demands. A snapshot of voltage and current phasors in this stage is shown in Figure 8 (c).
During this stage, the converter control starts to slowly take over and correct the error between the demands and the feedbacks, the so-called transitional stage to current source. Furthermore, the FRT event is detected and the converter control shifts to the FRT control mode, where priority is shifted from active to reactive current.
Finally, the steady-state stage in in Figure 8 (d) is more straight forward to describe where converter control is now fully in control of the situation, the PLL error and the FRT demand error have been corrected, and the injection is driven by the grid requirements and residual voltages at the terminals of the turbine. 64148 VOLUME 11, 2023 Authorized licensed use limited to the terms of the applicable license agreement with IEEE. Restrictions apply.  The stages can be observed in Figure ( In the initial sub-transient quasi voltage source stage, the current peaks reach values close to 2 p.u in phases 1 and 3. At this stage, the converter control hasn't still idenfitied the fault and tries to correct the errors between the demands and feedbacks based on the pre-fault setpoints. During the transient stage, the control starts to correct the errors and control the currents back to the desired demands and priority from the FRT control.

B. SUMMARY OF THREE STAGES
Based on the previous analysis, a summary of the three different stages is given below.

1) SUB-TRANSIENT STAGE
During this initial stage of the fault in a Type IV Wind Turbine, the control still has not yet identified a fault and transitioned to FRT control mode. This stage typically lasts between 1 and 10 ms and the IBR acts as a quasi voltage source, meaning that the currents can rise up to values higher than the in-fault steady-state magnitudes and present sequence component characteristics that are not correspondent to the FRT current priority.
The current magnitudes and angles are mainly affected by four interlinked factors: • Impedance between WTG and fault: The amplitude and rate of increase of the current is mainly affected by the network topology at the moment and the fault conditions in terms of impedance to the fault point, fault location, type of fault, resistance of the fault, and etc. The impedance is also affected by the WTG's reactor and transformer impedances.
• Hardware Transient Peak Limit: During this stage, a few safety mechanisms are usually put in place to avoid destructive currents in the converter and limit the current to certain value. The value of this limit for the WTG in this paper is 2 p.u. This limit will be explained in the next section of the paper.
• Pre-fault operational conditions of the WTG: Mainly the active power and voltage references will affect the magnitudes and angles of the pre-fault current and therefore can influence the transitional period when it comes to how fast the current will rise and how quickly the converter will identify the fault due to the voltage drop.
• Speed of control response: Finally, the current is also limited by the speed of the control and fault detection. If the rise of the current in time (dI/dT) is not so high and the detection is fast enough, there will be a tendency of the maximum current staying below the hardware transient limit. Furthermore, even without the imposed limits, the current would be limited by the control and therefore would be limited to a value lower than the expected value if a traditional voltage source behavior was considered.

2) TRANSIENT STAGE
As described in Figure (7), at this stage the control starts to react to the changes of the fault and identifies the FRT event. The currents start to be controlled and brought back to desired values (limited to around 1.1 p.u. usually). During the transient stage, the current shows a few characteristics of a voltage source and others of a current source. Similar to the sub-transient stage, the behavior of the current at the transient stage is very complex to determine. However, this stage is additionally influenced by the non-linearities introduced by the transitional stage to FRT control mode, as it heavily depends on the grid code, fault conditions and control design criteria for the bandwidths for the inner current control and PLL.

3) FAULT STEADY-STATE STAGE
At the fault steady-state period, which is usually starting from 50 ms, the values have either fully or almost fully settled to the desired in-fault injection depending on the grid code. The behavior of the converter can be modelled as a voltage and grid code dependant current source. This is the simplest part to be determined analytically as described in subsection III-B.

C. CLASSICAL REPRESENTATION OF AC-DC FAULT COMPONENTS
Traditionally, in conventional synchronous generation and even in Type III wind turbines with Doubly-Fed Induction Generator (DFIG) it is possible to represent the fault current  i sc (t) with an AC component i AC (t) and a DC component i DC (t) as shown in Equation (9) below [5], [14]. In an attempt to answer if the response of a Type IV wind turbine can be approximated to the response of a conventional generation, the Equation (9) is used.
where, I DC and I AC are the DC and AC magnitudes, T DC and T AC are the decaying DC and AC time constants and φ is the angle shift. These 5 different parameters are used to approximate a short-circuit current curve to the equation.
To fit the equation to the Type IV WTG response, a Particle Swarm Optimization (PSO) algorithm is applied with several different initial conditions and boundaries to the 5 previously described parameters in order to cover different possible combinations. As seen in Figure (10), no good fit and combination of the 5 parameters could be found since the initial 50 ms are highly non-linear and thus this simple equation should not be used. If the initial peak is fit, the algorithm cannot find a combination to fit against the rest of the signal and vice-versa, since the fault cannot be represented as a DC plus AC combination.
As seen in the theoretical analysis presented in this section, the short-circuit characteristics of a Type IV wind turbine presents complex behaviors that need to be further explored. In the next section, considerations will be made and supported by simulations about the three different fault stages presented in this section.

V. SCC CHARACTERISTICS OF FULL CONVERTER SYSTEM: CONSIDERATIONS
To support the analysis performed previously in Section IV, a deeper analysis about the differences from the simplified standard models will be made in this section, aided by simulation results. The plotted results are composed either by instantaneous waveforms, sequence components or RMS currents measured at the LV side of the transformer, where the calculation in p.u uses the base accordingly (for peak or RMS). The RMS current are calculated using full-cycle windows, apart from one comparison performed with half-cycle. The sequence components are obtained using the method described in IEC 61400-21-1 [33]. Due to the extensive number of simulations, only a subset of results are presented, where the conclusions can be extended to the rest of the results.

A. CONSIDERATIONS FOR THE SUB-TRANSIENT AND TRANSIENT STAGES (< 50 ms)
In this subsection the factors influencing the sub-transient and transient stages are presented.

1) CONVERTER CURRENT HARDWARE TRANSIENT PEAK LIMITATION
Different from the steady-state current limitations, the peak transient limits are designed to protect the semiconductors from dangerous overcurrents, that could lead to fast destruction of the equipment. This hardware (HW) limit is a very important consideration for the sub-transient stage, since all the current is fed through the power electronics interface, as opposed to Type III DFIG WTGs [14].
As seen in Figure (11) the instantaneous currents are shown. When different types of faults happen, the instantaneous currents increase rapidly as determined by the impedance between the WTG and the fault and the pre-fault operating conditions. In this case, different operating points at full rated active power and 25% power are also shown as it can be seen from the pre-fault currents. The fast increase in current is limited only by the hardware limit, which in this example is set to 2.0 p.u, as also shown in Figure (11).
As mentioned earlier, even if the converter transient limit was not implemented, the FRT control mode would identify the fault a few milliseconds after the fault inception. Because of that reason, the current of such converters cannot be naturally as high as the current expected from other types of generators where currents can be between 3 to 10 p.u or in some cases even higher [39].  calculations are done using full-cycle windows, where in the upper two sub-figures (12 -I-a) and (12 -I-b) the priority is given to only positive sequence reactive current while in the lower two figures the priority is given to both positive and negative sequence reactive currents. The same faults are applied in both cases and fault location is varied from 0% to 95% while voltage reference is also varied from 92% to 108%, hence several plots are condensed in the same image.
It can be observed that in the sub-transient stage (light red) the behaviors of (a) positive sequence only figures and (b) pos/neg figures are very similar. During the transient stage (light blue), the currents start to be controlled back to the desired values but still exhibit very similar behaviors until around 20 ms. Posterior to this time, currents start to be fully controlled where in (12 -I-b) negative sequence currents are brought to zero and (12 -II-b) negative sequence for unbalanced faults are injected. In RMS and short-circuit analysis tools, due to the nature of the calculation, the negative sequence transients injected when the control gives only priority to positive sequence current are often suppressed. The fact that the transients are not shown will affect the calculation of the total magnitude and angle of the transient current and therefore might affect equipment design and protection coordination studies.

3) POSITIVE SEQUENCE RESIDUAL VOLTAGE AND FAULT TYPE
As mentioned earlier, TSO's and other stakeholders are currently requesting data for short-circuit against the residual positive sequence voltage at the turbine terminals in different manners, as exemplified by the request for different cycles of the short-circuit (e.g. 1st, 3rd and 5th cycles). This information is requested for each fault type (i.e single-phase, two-phase and three-phase faults) and it might be motivated by the notion of the voltage dependent current source representation of a converter, where the response during the fault is mainly driven by the residual positive sequence voltage, which only holds true for the steady-state stage.
In order to challenge this fixed current source notion, Figure 13 can be used. Two different cases are presented with different SCR, X/R ratio and fault location. In both the cases, the positive sequence residual voltage and the steady-state current remains the same. It can be seen that although in steady-state the response is exactly the same, the sub-transient and transient stages are completely different, hence annulling the assumptions and the validity of such requirements.
If all the simulations are analyzed together as shown in Figure (14), it is possible to see the relationship between the maximum peak current and the positive sequence residual voltage in p.u. and the previously described variance across the positive sequence voltage bins. Since the positive sequence voltage is calculated based on the three phase voltage quantities as seen in IEC 61400-21-1 and other references [33], only three phase faults will usually bring all the positive sequence voltage down to values close to 0. That can be observed in the figure where for very low voltage bins (i.e. 0.1 and 0.2) only three phase faults are present, while for higher voltages 2 phase and 1 phase faults start to occur.
Furthermore, it can also be noted that lower residual voltage bins, i.e. less impedance between the turbine and fault, present less variation of peak currents as compared to higher residual voltage bins. A similar trend can also be observed for 2 phase and 1 phase faults. Additionally, its worth noting that the maximum peak currents are not lower for higher residual voltages. However, the variation is large since the influence of external factors such as SCR, X/R ratio fault impedance and location are relatively higher for such faults compared to those with lower residual voltages. Nonetheless, it can be seen that in most cases the current will hit the maximum value of 2.0 p.u even for very far away faults where the voltage bin is 0.9 p.u.

4) RETAINED VOLTAGE AT FAULT LOCATION
In the two Figures (15) and (16) the positive and negative sequence currents for three-phase and two-phase faults are shown. The effects of varying the retained voltage at the fault location are investigated. As mentioned before, the retained voltage is related to modifying the fault impedance to achieve a certain voltage drop at the fault location. In this case 0.005 p.u (i.e. solid/bolted fault), 0.3 and 0.7 p.u. In the cases plotted, fault location was varied from 0 % to 95 % and SCR was varied between 2 and 10, hence varying the total impedance between the turbine and the fault location. The power and voltage references were both kept constant at 1 p.u.
It can be seen that regardless of the fault location and SCR, the faults with lower retained voltage (i.e. lower fault resistance) present relatively higher values of currents. For three phase faults, the effect is more prominent on the positive sequence currents whereas for 2 phase faults the effect can be seen clearly on the negative sequence currents. The figures show only cases where the priority is given to only positive sequence reactive current. However, the same effect was seen in the cases where priority is given to both positive and negative sequence components.

5) OTHER FACTORS
As seen thus far, many different factors can affect the behaviors of the sub-transient and transient stages of the  fault. In Figure (17), simulations are shown for variations of Vref (Voltage reference pre-fault), X/R ratio, SCR, and Pref (power reference pre-fault), where fault location was varied from 0 % to 95 %. The different color gradients of blue, red and green were used to distinguish between three, two, and single phase faults. The same simulations and plots were carried out for priority of current to both positive and negative sequence, and the results were practically the same during the sub-transient and transient stages. • In Figures (17 -II-a) and (17 -II-b) the X/R ratio was modified, affecting then the impedance angle between the turbine and the fault. It can be seen that there are minor effects towards the transient stage of the fault, where the response can be affected by the phase angles.
• In Figures (17 -III-a) and (17-III-b), the SCR ratio was modified, affecting then the impedance magnitude between the turbine and the fault. It can be seen that the currents, specially the positive sequence, are more affected by the impedance magnitude (i.e. changing the SCR), specially in the second half of the first cycle.
• Finally, the prevailing power/reference change between 25% and 100 % can be observed in Figures (17 -IV-a) and (17 -IV-b), where a clear difference between the two power references can be seen in the positive sequence currents during the transient period.

6) FULL AND HALF CYCLE RMS CALCULATION
Driven by the discussions of the peak currents on the instantaneous signals, the analysis concerning full and half cycle RMS calculations becomes relevant. Different protection algorithms, especially impedance-based algorithms such as distance protection, make use of half cycle discrete fourier transforms (DFTs) and RMS calculation in order to obtain faster operation [40]. In Figure ( It can be concluded that: • Since the converter control generally does not have full control the current during the first 10 ms of the fault (first half cycle), the currents tend to be the highest during this period. Therefore, the maximum magnitude of the currents calculated by half-cycle are higher for most of the faults when compared to full-cycle calculation.
• If half cycle calculation is adopted, the RMS calculations will naturally be as close as possible to the hardware limitations presented before for the instantaneous currents as the first half cycle will generally not be as controlled as the second half of the first cycle.
• If full-cycle is used, there is generally a tendency of the peak magnitudes for 2 phase faults to be higher than 3 phase faults. This is however not observed in half-cycle calculations as their magnitudes in instantaneous currents are very similar (due to the HW limits), but the negative sequence currents from 2 phase faults take longer to be controlled. Therefore, the full-cycle calculations will generally show a slightly higher magnitude for 2 phase faults around 20 ms. This was also observed in Figure (12).
• The transient magnitudes of 3 and 2 phase faults are only slightly influenced by the pre-fault active power in the cases shown. This is however not true for 1 phase faults which are drastically lower in transient magnitude when the turbine is operating at 25% power. In this subsection, different analyses on the affecting variables were performed. In summary, some aspects like fault type, fault resistance/retained voltage and hardware limitations can influence the magnitudes and overall behavior of the faults in the transient periods. Other factors do not present a substantial impact on the fault behavior during these stages. It was seen that, despite fault currents and positive sequence residual voltage being the same at steady-state for two different faults, the transient behavior of such faults can be completely different. Furthermore, it was shown that half-cycle and full-cycle calculation techniques can greatly influence how the fault is perceived by measurement equipment that use such calculation methods. The steady-state stage of the fault current supplied by IBRs is generally better understood and calculated in existing tools in the market. In this subsection, some aspects of the fault current at the steady-stage stage will be explored and discussed.

1) CURRENT LIMITATIONS DURING NORMAL AND FAULT OPERATION
Initially, it is important to point out the fact that not all the IBRs in the network are limited to supplying a maximum of around 1.1 p.u. of current. In reality, the specific turbine design selected for this paper allows for higher current operation of around 1.2 p.u during normal operation. However, due to grid code regulations, it is often opted to limit the current during faults to around only 1.1 p.u in an attempt to make the IBR currents more predictable.
Figure (19) shows results from three simulations run under different pre-fault voltage conditions. This is to demonstrate the earlier presented scenario where the pre-fault steady state current can exceed the in-fault steady state current under some operating conditions. This is usually the case when the converter is operating at a low voltage reference for example 92% and high power reference such as 100%. This illustrates that the short-circuit current during fault is not only limited by the hardware limitation of an IBR, but is also limited by fault requirements and other factors.

2) ACTIVE CURRENT LIMITATIONS IN-FAULT
As established before in Section III-B, the reactive current injection is mainly driven by the residual voltage measured during fault, while the active current is injected on the remaining headroom up to the limit of 1.1 p.u, following the turbine's capability. In Figure (20), the total current as well as reactive and active currents are plotted for both cases.
Theoretically, the wind turbine has the capability of injecting the maximum allowable active current of ≈ 0.48 p.u. However, the topology of the grid during fault might not allow such current to be injected due to lack of resistance/load. Therefore, it cannot be assumed that for any given fault the converter will always inject 1.11 p.u as it will depend also on the grid topology and if the active current can actually be injected.
In Figure ( 20), Case 1 has a voltage reference of 1.05 p.u. and a fault location equal to 50%. For case 2, these values are 0.95 p.u. and 60%. Except for voltage references and fault locations, both cases have the exact same fault condition. It can be seen that although the injected reactive current is the same (around 1 p.u.) for both cases, the active current is different. In Case 1, the active current is around 0.47 p.u. and the total current is around 1.11 p.u. However, for Case 2 the injected current is lower and closer to 1 p.u as the active current is quite reduced during the fault.

3) SENSITIVITY ANALYSIS ON DIFFERENT VARIABLES
In Figure (21), several different comparisons for the steady-state total current can be seen. Each subplot has in its x-axis the residual positive sequence voltage bins from 0.1 to 0.9 p.u and in the y-axis the total steady-state RMS current in p.u.
For Sub-figures (21 -a), (21 -b) and (21 -c), only cases with three-phase faults are shown to better visualize the effects. If two-and single-phase are included, the effects can be masked due to higher variation of fault currents. All the other variables present in Table (1) such as power reference, current priority, SCR, X/R ratio, fault location, fault resistance are varied to yield different retained voltages: • In general, it can be seen that for deep faults of roughly 0.3 p.u of residual terminal voltage or less, currents will rarely be lower than 1.1 p.u, since the converter will be injecting the maximum reactive current and also some active current in most of the cases.
• Pre-fault prevailing voltage (i.e. voltage reference): Sub- figure (21 -a) shows that fault currents at higher prevailing voltages tend to vary less than lower prevailing voltages. This relation can be seen in equations shown in Section IV, where for higher prevailing voltages, the reactive current tends to hit the maximum current of 1 p.u. even at higher residual positive sequence voltages.
• K Factor: As seen in Sub- figure (21 -b), it can be observed that for higher values of the multiplier, the converter will inject more total current even for shallow 64154 VOLUME 11, 2023 Authorized licensed use limited to the terms of the applicable license agreement with IEEE. Restrictions apply.
faults. Hence, higher median values in the box plots and less variation.
• Retained voltage at the fault location (i.e. fault impedance): it can be observed in Sub-figure (21 -c) that generally higher fault impedances tend to cause more variation of the fault current as opposed to more solid faults. It can also be seen that only solid faults with 0 retained voltage can originate cases where the residual voltage at the turbine LV terminals is lower than 0.3 p.u. On the other hand, for sub-figures (d), (e) and (f), the K factor, current priority and relation between the peak current the total steady-state current are investigated. In these subfigures, cases with all three types of faults and all other variables in Table (1) were included in the analysis to observe the effects on the three studied variables.
• Prevailing/reference active power: It can be seen in Subfigure (21 -d) that for shallow faults with lower power reference of 0.25 p.u the steady-state current tends to be lower and vary more than when the prevailing power is 1 p.u. This can be explained by the fact that if small amounts of reactive current are needed, the converter can push more active current as long as it can produce it and the system has loads to dissipate this active power.
• Current Priority: In sub-figure (21 -e), it can also be observed that lower currents during fault are also directly related to the current priority explained in Equations (3) and (4) in Section III-B. Consider all the unbalanced fault cases where priority is given only to positive sequence Q − Pos and the calculated reactive current is anywhere below the limit of 1 p.u. If Q − Pos/Neg priority is used instead, the total reactive in many cases will be reaching the limit of 1 p.u. due to the equal priority given to positive and negative sequence.
• Peak Current: Comparing the steady-state total current to the peak current in (21 -f), it can be seen very high variation of peak current is observed specially for more shallow faults. The peak current was divided in four different bins. For faults in voltage bins lower than 0.3 p.u., the peak current will likely not be below 1.5 p.u. As faults become more shallow, the maximum current peak can be less than 1.1 p.u. In the mid range of residual voltage, between 0.4 and 0.7 p.u, even when total steady-state current is as low as 0.5 p.u. during the steady-state, the current peaks can be almost 2 p.u. Finally, for very shallow faults, the current peaks can still be quite high, although more likely to be between 1.1 p.u. and 1.9 p.u. As discussed, different factors affect the in-fault current behavior. Due to the complexity of the response, it is difficult to formulate a multi-dimensional mathematical co-relation with all variables. Thus, a more intuitive approach is to do statistical analysis. The main aim being to establish interrelationships between different variables and the short-circuit current. This analysis will follow in the next section.

VI. STATISTICAL ANALYSIS
Posterior to performing several analyses, it is also interesting to explore the correlations of the several variables on to the different stages of the fault. This was done by applying multiple regression analysis (MRA) to model the relationship described in Table (2). This statistical method is used to model the relationship between a continuous dependent variable and one or more independent variables (categorical or continuous) [41].
The coefficients extracted from the multiple regression analysis are presented in Table (2). The coefficients represent the change in the dependent variable (y) for a unit change in the corresponding independent variable (x), holding all other independent variables constant. They quantify the relationship between each independent variable and the dependent variable, allowing to make predictions and understand which independent variables have the strongest impact on the dependent variable. In order to understand which ones affect the most each of the variables, a standardized scale was applied by subtracting the mean of the coefficients and dividing by the standard deviation. This will return the standardized scale for each column where the coefficients range from -1 to 1. A negative coefficient represents a inverse relationship and a positive coefficient represents a direct coefficient.
In Table (2), the three stages are represented by the total positive sequence I tp and negative sequence current I tn measured at each stage. The values were measured by extracting the maximum current within the first cycle for the subtransient (<10 ms), second cycle for the transient (<40 ms) and fifth cycle for the steady-state (>100 ms). The ''Z Magnitude'' and ''Z Angle'' from the WTG to the fault were computed by summing all the impedances between the converter terminals including the reactor, WTG transformer and network impedance. It is important to mention that these values are just a minor representation of all the behaviors and act only as illustrative representations of the entire dynamics seen in these stages.
General comments about correlations: • The fault impedance is highly inversely proportional to all the stages of the fault current, with coefficients close to -1 for all the variables.  -Affecting variables -additionally to the affecting variables before, the SCR, X/R, current priorities, k factor, impedance angle of the impedance to fault start to play a role.
• For the steady-state stage, it can be observed that all the variables have some influence on the results. The statistical analysis corroborates with the analysis done previously and the theoretical expectations that show very little influence of grid code related variables at the early stages of the fault since the converter control has not yet identified the fault yet. It also shows that isolated variables such as SCR, X/R ratio and fault location do not present much influence at the early stages of the fault.
The dominant characteristic is the magnitude of the impedance between the turbine and the fault, which is a combination of these three parameters together. The fault at the transient stages is further influenced by the prevailing active power, the fault type and the fault impedance. Once the fault transitions to the steady-state stages, these variables start to influence more the current injected.

VII. DISCUSSIONS AND FUTURE WORK
The scenarios simulated and analyzed can faithfully represent a wide range of different conditions that the WTG can experience. Considering all the characteristics discussed previously, it can be reasonable to affirm that pin pointing the short-circuit contribution of Type IV wind turbines with realistic models is a far more complex task than anticipated by most widely accepted practices in the industry.
As it was shown, the short-circuit current contribution from a Type IV wind turbine does not fit well with the defined equations and behaviors seen in conventional synchronous machine-connected generation and Type III DFIG wind turbines. The different stages are highly influenced by the non-linearities of the proprietary controls utilized, the grid topology, fault conditions and the inherit current limits of power electronic converters.
Manufacturers can provide the maximum currents that a converter might inject during the transient and steady-state based on the peak transient current limit and the steady-state maximum current allowed, which were 2 p.u and 1.11 p.u, respectively, for the turbine in consideration. However, as presented via different examples in the paper, the converter will not always provide maximum current for various reasons. Thus, it is not a trivial task to provide total SCC for a converter system for all available scenarios, because the possible outcomes can be enormous with several dependencies.
For the steady-state stage of the fault, more standardized and analytical solutions can be put in place in order to ensure that the fault current at such stages is well represented. It could be concluded that simple short-circuit analysis tools based on existing standards do not represent the current dependencies on voltage and grid codes. Phasor or RMS models can be used to account for such dependencies of the current at this stage and can be validated by EMT simulations. Regarding the sub-transient and transient stages, it was shown that dynamics are far more complex and highly nonlinear. EMT models can faithfully represent such dynamics and present accurate results. When it comes to peak currents for equipment design and studies for fast sub-cycle protection algorithms, it becomes clear that EMT simulations are desired.
It is completely understandable that system designers need more information to improve several aspects of the design, but it is also important to point out the its not feasible to supply such information without standardization and well defined processes. Increasing requests without collaboration and agreement from different stakeholders can make processes for both manufacturers and designers even more complex than nowadays.
As the integration of IBRs is increasing in several parts of the world, for future work, several different aspects should be taken into account as a way of improving the understanding on how the short-circuit contribution of a certain equipment or plant looks like: • WT manufacturers, WPP developers, TSOs and any other interested parties need to work together to find out what information about short-circuit contribution is critical and needed on project to project basis to help each other out and come-up with the best possible solution.
• A standardized way of representing the short-circuit current contribution as well as collecting and supplying information that can be used to improve modelling and design aspects, considering pre-fault and during fault conditions as well as grid codes and other regulations.
• Although EMT simulations present a high accuracy, their use also presents challenges concerning computational intensity. In this sense, a simplified but more accurate representation of SCC for long-term planning and equipment design in power systems could be used. This lighter simulation can be capable of modelling the peak currents and other relevant information in a more satisfactory way. This could be done either in analytical or data-driven manners.
• Due to increasing research being done in grid forming control topology for IBRs, it is also important to understand similarities and differences during fault for grid forming Type IV Wind Turbines compared to grid following topologies.

VIII. CONCLUSION
This paper explored and shed light on the complexity of short-circuit current contribution from full-converter Type IV wind turbines. Given the increasing penetration of IBRs, constant challenges arise on equipment design and modern protection schemes for faster than ever detection and clearing of the fault. Therefore, a more comprehensive understanding on the transient phenomena of full-converter will become ever more necessary. The learnings of this paper can also be expanded to other full-converter connected IBRs that might share the control topology and a few other properties explained in the paper. Differently than conventional synchronous machines and Type III DFIG wind turbines, the phenomena during a fault in Type IV wind turbines can be highly non-linear. Therefore, through the use of a field-validated PSCAD model, more than 20000 scenarios were simulated and three different stages of the fault were identified and explored. It was found that during the sub-transient and transient stages, the converter acts as a quasi voltage source and then transitions to the more well known voltage and grid code dependant current source. These stages are heavily affected by the fault conditions, converter control parameters, WTG's pre-fault operating conditions, WTG's equipment impedances and network topology, which make it far more complicated to compute when compared to more traditional generation. At the end, an statistical analysis is carried out to determine the influence of each variable in the fault current.
For future research, it can be expected that more accurate SCC calculation of IBRs will become important for the industry in general. More standardization in the way information is requested and supplied should be done, specially for Type IV wind turbines and other full-converter IBRs. The studies through EMT models with the actual control source code are crucial and will become even more important for detailed representation of the short-circuit current and other dynamics during faults. Nonetheless, less computationally intensive solutions such as reduced-order model representation through phasor/RMS models or data-driven machine learning models might be useful for specific purposes where simplifications can be allowed, such as long-term planning of the system.

LEGAL DISCLAIMER
Figures and values presented in this paper should not be used to judge the performance of Siemens Gamesa Renewable Energy technology as they are solely presented for demonstration purpose. Any opinions or analysis contained in this paper are the opinions of the authors and not necessarily the same as those of Siemens Gamesa Renewable Energy.