Open access peer-reviewed chapter

# An Algorithm for Default Detection of Wind Turbine Generators

Written By

Jigneshkumar P. Desai

Reviewed: 04 April 2022 Published: 28 May 2022

DOI: 10.5772/intechopen.104793

From the Edited Volume

## Wind Turbines - Advances and Challenges in Design, Manufacture and Operation

Edited by Karam Maalawi

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## Abstract

The protection of the wind turbine generator (WTG) required discrimination between internal and parallel WTG faults. Furthermore, it must discriminate the fault of its feeder line and parallel feeder line. This chapter describes the protection of wind turbine generators based on fault current and voltage analysis, which can identify the instantaneous operation, delay operation, or immune operation. A proposed Algorithm based digital relay is presented to provide all the different fault detection in a single unit suitable for internal and external fault protection of wind turbine generator. The main challenge to this scheme is that fault resistance may wrongly operate the scheme in some rare conditions. The phase angle of negative sequence current components determines the type of fault. The algorithm used negative sequence current and voltage to positive sequence current and voltage ratio, which is less than the set value in case of external fault. The fault seniors have been explained using simulation results on the wind turbine generator system modeled in a software environment.

### Keywords

• internal fault
• feeder
• positive sequence current
• relay
• wind turbine generator

## 1. Introduction

The parts of the wind turbine generator are shown in Figure 1. Blades are connected to this rotor hub. By rotating the motor shaft angle, one can turn the blade’s direction, resulting in a change in mechanical power. This rotational mechanical energy rotates the rotor, and by using a gearbox, speed can be changed. By changing the speed, torque will be changed. The frequency of the generated voltage depends on the speed and number of poles. The variable frequency is converted into the constant frequency using a power converter. At this stage, two converters are used. One is an AC-DC converter, and the second is a DC-AC converter called a back-to-back converter. This is often called a gear-less wind turbine generator [2]. As electrical technology is very advanced, mechanical energy to electrical energy can be converted with different machines. Based on this machine used, the wind turbine generators are classified. The most common challenges for the wind turbine are as follows: (1) highly variable wind power injection into the grid, (2) increased penetration of wind energy, (3) Electrically weak distribution network, and (4) heavy reactive power burden by Induction generator (IG).

The classification of wind energy conversion system (WECS) is shown in Figure 2. Squirrel cage induction generators (SCIG) are a traditional method, but one cannot get maximum power at different wind speeds. The SCIG is generally known as a fixed-speed wind turbine. At variable rates, wind turbine generators are two types which are gear-less and with gear. Gear-less wind turbine generators may be running at a slower speed, but one can change the number of poles. The wound rotor synchronous generator (WRSG) and permanent magnet synchronous generator (PMSG) is the gear-less wind turbine. The wound rotor synchronous generator (WRSG) and permanent magnet synchronous generator (PMSG) maybe with gear also [3]. Doubly fed induction generator (DFIG), SCIG, wound rotor induction generator (WRIG) with variable rotor resistance also come under the gear category.

## 2. Grid connected operation of SCIG

The SCIG has the following main parts: (1) Gear Box, (2) cage induction generator, (3) soft starter, and (4) Capacitor for power factor compensation.

The SCIG is a very simple structure of WTG used in the system. SCIG is directly connected to the grid using a starter and transformer. A soft starter is available in starting only to limit high inrush current. This is the most widely used structure worldwide due to less maintenance and simple design. The main disadvantage is that full power cannot be extracted from the grid. The SCIG needs high reactive power, which the capacitor bank locally supplies, as shown in Figure 3. The machine is run above synchronous speed using pitch control.

## 3. Configuration of wind farm

A wind farm composed of six 1.5 MW wind turbines is connected to a 25 kV distribution system that exports electricity to a 120 kV network via a 25 km long feeder from a 25 kV bus 4. Three 1.5 MW wind turbines pairs simulate the 9-MW wind farm. Wind turbines use squirrel cage induction generators (SCIG) [5]. Figure 4 shows the system considered for protection in which three wind turbine generators are connected to the grid.

The stator winding is connected directly to the 60 Hz grid, and a controllable-pitch windmill drives the rotor [6, 7]. The pitch angle is controlled to limit the generator’s output power to its nominal value for winds exceeding the little velocity (9 m/s). A protection system is installed at each wind generator from W1 to W3, which measures voltage, current, and speed. Reactive power absorbed by the IGs is partly compensated by capacitor banks connected at each wind turbine low voltage bus [8, 9, 10]. The rest of the reactive power required to maintain the 25-kV voltage at bus B4 close to 1 pu is provided by a 3-Mvar STATCOM with a 3% droop setting. Modeling of Wind Turbine Generator is carried in MATLAB Software [11]. The data of wind turbine generator modeling is shown in Appendix A.

## 4. Protection of wind turbine generator

The digital protection system installed on W1 to W3 consist of following protections covers in single digital relay for wind turbine generator [12].

1. Instantaneous AC overcurrent

2. Positive-sequence AC overcurrent

3. Unbalance AC current

4. Positive-sequence under voltage

5. Positive-sequence under voltage

6. Negative-sequence unbalanced voltage

7. Zero-sequence unbalanced voltage

The desired protection for relay 1 at W1, relay 2 at W2, and relay 3 at W3 are shown in Table 1 for different fault locations.

Fault positionRelay 1 operationRelay 2 operationRelay 3 operation
F1InstantaneousNon-operationNon-operation
F2Non-operationInstantaneousNon-operation
F3Non-operationNon-operationInstantaneous
F4InstantaneousInstantaneousInstantaneous
F5InstantaneousInstantaneousInstantaneous
F6InstantaneousInstantaneousInstantaneous
F7DelayedDelayedDelayed

### Table 1.

Desired operation of digital relay R1, R2, and R3 at W1, W2, and W3 respectively.

### 4.1 Protection algorithm

The relay R1, R2, and R3 are located at Bus 1, Bus 2, and Bus 3. The algorithm is explained in this section by considering Relay R1 to protect W1 against internal faults F1. For faults F4, F5 and F6 at POC at Bus 4, R1 reacts instantaneously as both these three faults impact the W1 directly. On the other hand, the relay R1 remains stable for F2, F3 and F7 and maybe operate as a backup to the primary relay addressing these faults. Here, F2 and F3 are parallel feeder faults considered external faults for F1. F7 is a external fault in the grid system. The protection algorithm for such desired operation as per Table 1 is shown in Figure 5. As per the Algorithm, relay R1 measured three-phase voltage and current Vabc and Iabc with the help of PT and CT in the beginning [13]. Using the symmetrical component method, Positive sequence, negative sequence, and zero sequence voltage and current are V1, V2, V0 and I1, I2, I0 respectively have been calculated. Based on the different conditions as shown in Figure 5, the tripping commands have been sent to the circuit breaker of W1. The next section will describe how the Algorithm detects LG, LL, LLL, LLLG faults for internal and external fault conditions.

## 5. Different internal and external fault detection by digital relay

### 5.1 LG faults

LG faults have been applied at F1 to F7 locations as internal and external faults. Considered F1 fault as LG fault and used at 15 s of simulation time for 0.3 s duration which is an internal fault for W1. in this case-1, the voltages are unbalanced significantly which has V0/V1 ratio found 0.985pu which is greater than a set value and as per algorithm the relay issue tripping after 0.001 s which instantaneous. It is important to note that in this case, relay R2 at W2 and R3 at W3 are not affected and remain immune. The tripping coordination of R1 to R3 for this case-1 is shown in Figure 6. Figure 7 shows that positive sequence and zero sequences are present significantly during the fault, and the ratio of V0/V1 exceeds the set value. Similarly, LG fault has been applied at the F6 location. In this case, the fault is at POC, which required the operation of all the relays operated at 0.2 s. Table 2 shows the other faults and measurement of current and voltage sequence components during the faults at bus 1.

Internal fault typeFault locationMax (Ia,Ib,Ic) (p.u)I1 (p.u)I2/I1 (p.u)V1 (p.u)V2/V1 (p.u)V0/V1 (p.u)
LGBus 1R1:0
R2: 0.977
R3:0.979
R1:0
R2:0.983
R3:0.9846
R1:0
R2:0
R3:0
R1:0.998
R2:0.979
R3:0.979
R1:0
R2:0
R3:0
R1:0.985
R2:0.0001
R3:0.0001
LLBus 1R1: 0
R2:0
R3:0
R1: 0
R2:0
R3:0
R1:0.037
R2:0.022
R3:0.022
R1:0.821
R2:0.9015
R3:0.9015
R1:0.458
R2:0.2568
R3:0.2568
R1:0
R2:0
R3:0
LLGBus 1R1:0
R2:0
R3:0
R1:0
R2:0
R3:0
R1:0.037 R2:0.022 R3:0.022R1:0.0821
R2:0.9015
R3:0.09015
R1:0.458
R2:0.2568
R3:0.2568
R1:0.662
R2:0
R3:0
LLLBus 1R1:0
R2:0
R3:0
R1:0
R2:0
R3:0
R1:0
R2:0
R3:
R1:0.738
R2:0.738
R3:0.738
R1:0 R2:0 R3:0R1:0
R2:0
R3:0
LLLGBus 1R1:0
R2:0
R3:0
R1:0
R2:0
R3:0
R1:0
R2:0
R3:0
R1:0.665
R2:0.738
R3:0.738
R1:0 R2:0 R3:0R1:0
R2:0
R3:0

### Table 2.

Internal fault on feeder 1, 2, and 3 near SCIG.

### 5.2 LL faults

As internal and external faults, LL faults have been applied at F1 to F7 locations. Considered F2 fault as LL fault and used at 15 s of simulation time for 0.3 s duration which is an internal fault for W2. In this case-2, the positive sequence voltages less than set value and as per the algorithm the relay issue tripping after 0.001 s. It is important to note that in this case, relay R1 at W1 and R3 at W3 are not affected and remain immune. Additionally, It provides backup protection after 0.15 s and 0.14 s by R1 and R3 to R2. The V1 and V2/V1 variations are shown in Table 2 during the LL fault at bus 2.

### 5.3 LLG faults

As internal and external faults, LLG faults have been applied at F1 to F7 locations. Considered F3 fault as LLG fault and used at 15 s of simulation time for 0.3 s duration which is an internal fault for W3. in this case-3, the positive sequence voltages less than set value and as per algorithm the relay issue tripping after 0.001 s. It is important to note that in this case, relay R1 at W1 and R3 at W3 are not affected and remain immune. Additionally, It provides backup protection after 0.15 s and 0.14 s by R1 and R2 to R3.

### 5.4 LLLG faults

LLLG faults have been applied at F1 to F7 locations as internal and external faults. Considered F4 fault as LLLG fault and used at 15 s of simulation time for 0.3 s duration which is the internal fault for W1. in this case-4, the positive sequence voltages less than set value and as per algorithm the relay issue tripping after 0.001 s. In this case, relay R2 at W2 and R3 at W3 is also instantaneous as the fault is on the point of Common Coupling (POC). Table 3 shows that I2/I1 and V1 change significantly during fault at bus 4.

Fault typeFault locationMax (Ia,Ib,Ic) (p.u)I1 (p.u)I2/I1 (p.u)V1 (p.u)V2/V1 (p.u)V0/V1 (p.u)
LGBus 4R1:0
R2:0
R3:0
R1:0
R2:0
R3:0
R1:0.02
R2:0.02
R3:0.02
R1:0.88 R2:0.88 R3:0.88R1:0.24
R2:0.24
R3:0.24
R1:0.76
R2:0.76
R3:0.76
LLBus 4R1:0
R2:0
R3:0
R1:0
R2:0
R3:0
R1:0.05
R2:0.05
R3:0.05
R1:0.545 R2:0.545
R3:0.545
R1:1.0
R2:1.0
R3:1.0
R1:0
R2:0
R3:0
LLGBus 4R1:0
R2:0
R3:0
R1:0
R2:0
R3:0
R1:0.046
R2:0.046
R3:0.046
R1:0.473
R2:0.473
R3:0.473
R1:1.0
R2:1.0
R3:1.0
R1:0.994
R2:0.994
R3:0.994
LLLBus 4R1:0
R2:0
R3:0
R1:0
R2:0
R3:0
R1:0
R2:0
R3:0
R1:0.0007
R2:0.0007
R3:0.0007
R1:0
R2:0
R3:0
R1:0
R2:0
R3:0
LLLGBus 4R1:0
R2:0
R3:0
R1:0
R2:0
R3:0
R1:0
R2:0
R3:0
R1:0.0007
R2:0.0007
R3:0.0007
R1:0
R2:0
R3:0
R1:0
R2:0
R3:0

### Table 3.

Internal fault on feeder 1, 2, and 3 near POC.

### 5.5 LLL faults

LLL faults have been applied at F1 to F7 locations as internal and external faults. Considered F5 fault as LLL fault and used at 15 s of simulation time for 0.3 s duration which is the internal fault for W2. In this case-5, the positive sequence voltages less than set value and as per algorithm the relay issue tripping after 0.001 s. It is important to note that in this case, relay R1 at W1 and R3 at W3 is also instantaneous as the fault is on the point of Common Coupling (POC).

### 5.6 External fault

When LG fault is applied on the F7 location, which is in the grid and considered an external fault to the wind farm, the ratio of negative sequence voltage to positive sequence voltage and negative sequence current to positive sequence current is less than the set value [14]. So, as per the algorithm, relays R1 to R3 issued delayed tripping at 0.21 s after the fault instant. For all the other external faults, the variation of V1, V2/V1, and I2/I1 are shown in Table 4.

Fault typeFault locationMax (Ia,Ib,Ic)
(p.u)
I1 (p.u)I2/I1 (p.u)V1 (p.u)V2/V1 (p.u)V0/V1 (p.u)
LGBus 5R1:0
R2:0
R3:0
R1:0
R2:0
R3:0
R1:0.024
R2:0.024
R3:0.024
R1:0.845
R2:0.845
R3:0.845
R1:0.289
R2:0.289
R3:0.289
R1:0
R2:0
R3:0
LLBus 5R1:0
R2:0
R3:0
R1:0
R2:0
R3:0
R1:0.051
R2:0.051
R3:0.051
R1:0.574
R2:0.574
R3:0.574
R1:0.897
R2:0.897
R3:0.897
R1:0
R2:0
R3:0
LLGBus 5R1:0
R2:
R3:
R1:0
R2:
R3:
R1:0.042
R2:
R3:
R1:0.479
R2:
R3:
R1:0.877
R2:
R3:
R1:0
R2:
R3:
LLLBus 5R1:0
R2:0
R3:0
R1:0
R2:0
R3:0
R1:0
R2:0
R3:0
R1:0.001
R2:0.001
R3:0.001
R1:0
R2:0
R3:0
R1:0 R2:0 R3:0
LLLGBus 5R1:0
R2:0
R3:0
R1:0
R2:0
R3:0
R1:0
R2:0
R3:0
R1:0.001
R2:0.001
R3:0.001
R1:0
R2:0
R3:0
R1:0
R2:0
R3:0

### Table 4.

External fault of W1, W2, and W3 at grid side.

## 6. Challenges and possibilities

The main challenge in this protection scheme is that the relays R1 to R3 are affected by fault resistance while power swing occurs near them, and they cannot detect it. It is important to note that power swing blocking and out-of-step tripping functions are available to handle these challenges in the existing system [15].

## 7. Results and discussions

The results of Tables 24 clearly show the quantity such as instantaneous overload current (Ia, Ib, Ic), I1, I2/I1, V1, V2/V1, and V0/V1 changes during different faults differently. This variation is used in the digital relay to identify internal and external feeder faults. The relays at W1 to W3 remain immune due to correct settings during grid faults. In this protection scheme, instantaneous overload current (Ia, Ib, Ic) provides instantaneous AC Over current, I1 provides AC Overcurrent (positive-sequence), I2/I1 provides Ac Current unbalance, V1 provides AC over and under-voltage (positive sequence), V2/V1 provides AC unbalance voltage (negative sequence), V0/V1 provides C unbalance voltage (zero sequences) protection to W1 to W3 against internal and external feeder faults correctly.

## 8. Conclusions

F1 from F2 and F3 can be detected using positive sequence voltage because the fault current of F2 and F3 can be seen at W1 via step-up transformer and feeder, due to which current is reduced compared to F1 in case of LG fault. While W2 sees F2 directly and W3 sees F3 directly, that is not affected F1, which is a parallel feeder fault. In the case of external fault, zero sequences cannot be used as they are trapped in the winding. So algorithm used negative sequence current and voltage to positive sequence current and voltage ratio, which is less than the set value in case of external fault. So, R1 to R3 does not operate. The proposed Algorithm based digital relay provides all the different fault detection in a single unit suitable for internal and external fault protection of WTG. The main challenge to this scheme is that fault resistance may mal-operate the scheme in some rare events.

## Conflict of interest

The authors declare no conflict of interest.

SCIG data
ParameterSymbolUnitValue
Nominal powerPnVA3.33 MVA
Line-to-line voltageVnVolt575
frequencyfnHz60
StatorRspu0.004843
StatorLlspu0.1248
RotorRr’pu0.004377
RotorLlr’pu0.1791
Magnetizing inductanceLmpu6.77
Inertia constantHs5.04
Friction factorFpu0.001
Pairs of polesP3
Nominal wind turbine mechanical output Power (W)PmW3 MW
Base wind speedNwm/s9
Base rotational speedNpu1
Maximum power at base wind speedPm(max)pu1
Pitch angle controller gainKp and Kipu5 and 25
Maximum pitch angleβmaxdeg45
Maximum rate of change of pitch angle/dtdeg/s2

## Abbreviations

 WTG wind turbine generator IG Induction generator WECS wind energy conversion system SCIG squirrel cage induction generators WRSG PMSG permanent magnet synchronous generator WRSG wound rotor synchronous generator WRIG wound rotor induction generator KV Kilo Volt STATCOM Static Var Compensator W1 Wind turbine 1 F1 Fault 1 POC Point of Common Coupling R1 Relay 1 LG Line to ground LL Line to line LLL Line to line to line LLG Line to line to ground LLLG Line to line to line to ground I1 Positive sequence Current V1 Positive sequence Voltage I2 Negative sequence Current V2 Negative sequence Voltage I0 Zero Sequence Current V0 Zero Sequence Voltage pu Per unit

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Written By

Jigneshkumar P. Desai

Reviewed: 04 April 2022 Published: 28 May 2022