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Impact of Renewables on Protection Schemes

IPCGRID March 27, 2019

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Pacific Gas and Electric (PG&E)

Peak Demand PG&E: 23 GW

California Control Area: 58 GW

35,000 Protective Relays

100+ RAS and SPS

400,000Solar Connections

PG&E

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Drivers for Renewable EnergyCalifornia Legislation

Increase Energy Derived from Renewable Energy Sources to 100% by 2045 via:

Senate Bill SB 350

Senate Bill SB 100

Renewable Portfolio Standard (RPS) Targets

25% by end of 2016 (presently at 29%)

33% by end of 2020

40% by the end of 2024

45% by the end of 2027

60% by the end of 2030

100% by the end of 2045

12000 MW from DER by 2020 ( DER is defined as generation < 20MW)

Reduce Greenhouse gas emissions by 40% from 1990 levels via:

Senate Bill SB 32

AB 197

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Realtime Renewable Penetration in CAISO Area

63.5%

Recently reached 63.5% renewables generation.• 70% was PV• 17% was wind

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IBR (Inverter Based Resource) Protection Issues

Traditional Generation fault current characteristics– Synchronous Generation

• Produces phase fault current in 3 stages.

– X”d Subtransient : High level fault current (8-12pu ) typically lasts approximately 5-6 cycles

– X’d Transient: Lasts 10-12 cycles– Xs Synchronous: Fault current magnitude can range

from 1.0 – 1.2 pu.– Produces I2 and I0 current.– Voltage source model

• Modeling is very well understood and repeatable.– Manufactures provide test data to populate the required

parameters.• Existing fault simulation software provides good modeling which has

been validated with actual fault data.• Traditional protection relays are designed around these characteristics.

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IBR Protection Issues Inverter Based Generation fault characteristics

• PV (photovoltaic)– Does not have the rotational inertia of the rotor and excitation of the

field.– Generally a current source with minimal voltage support.– Traditional protection methods may not work.

• Produces low level fault current typically 1.1-1.3pu.• Most inverter models do not produce I2 or I0.

– The fault characteristic is dependent on the inverter switching control which varies among manufactures.

– Tradition fault software is not configured to accurately model inverter based generation.

– Fault simulation software presently uses a synchronous generator model that is modified to approximate the characteristics of an inverter, however this is still a voltage source model that does not adequately represent the actual fault current characteristics and voltages.

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IBR Fault Current CharacteristicsRenewable Types

Wind

Type 3

Wind

Type 4

PV

No GND, No 3Io May have I2 Crow Bar 2-3 Cycles Stator Connected to Grid Converter Controls Excitation

No GND, No 3Io No I2 No Inertia May have short current spike Low fault current (1.1-1.3 pu) Similar to PV Inverter

No GND, No 3Io No I2 No Inertia May have short current spike Low fault current (1.1-1.3 pu)

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IBR Protection Issues

Inverter based generation fault

characteristics PV (photovoltaic)

Current Spike 2.0 pu for 4.0 msec too fast for relay

detection.

Current after fault detection just over 100%

Typical short circuit fault current for Synchronous Machines

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Sequence ComponentsLL FaultSLG Fault

I11

I12

Z1G

1 Z1

L*m

Z1L*

(1-m

) Z1

G2

Z2L*

m I2

1 =0

Z2G

1

I22

Z2L*

(1-m

) Z2

T2

Positive Sequence

Negative Sequence

Rfault

G

Inverter System

Z1T1

Z1T2

Z1G

2

Z2T1

• IBR based generation typically has high Z2 and Z0 impedance.• For SLG and Line–Line faults, high Z2 results in a lack of negative sequence current from the inverter. • The typical interconnection transformer configuration of wye-gnd/delta will provide zero sequence current for

operation of the ground overcurrent elements.• The inverter will provide positive sequence current as long as it is paralleled with a system that has low negative

sequence impedance.• If separated from the system the inverter high negative sequence impedance results in greatly reduced fault

current flow and non-detection of the fault from inverter based generation. • Leads to the observation as inverter based generation is increased could result in decreased detection or non-

detection of SLG and LL faults especially on transmission system very close to inverter based generation or in a radial line configuration.

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Sequence Components

DLG Fault

The resulting phase current sequence components consist of positive and zero sequence with theresulting fault current reduced due to the lack of negative sequence current. This result is not assevere as the reduction for SLG and L-L faults.

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IBR Protection Issues

• Phase overcurrent protection relies on the magnitude of the fault current.

• The pick-up needs to be high enough to not constrain the protected equipment and low enough to detect in section faults.

• The low level of fault current produced by IBR’s can be a challenge to setting overcurrent based protection.

• IBR fault current is typically limited to 1.0 -1.2 pu.• Setting an overcurrent element at 60% of minimum fault current results in a

setting of (1.1 *0.60) = 0.66pu.• This will limit the output of the IBR.

Phase Overcurrent

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IBR Protection Issues

• Ground overcurrent elements use zero sequence or ground current as the measured quantity.

• During normal balanced conditions zero sequence current is ideally zero, the pick-up can be set under generator and/or equipment maximum loading and is not influenced by the current limiting function of the inverter.

• Although inverter based generation does not inject zero sequence current, the typical interconnection transformer configuration of wye-gnd/delta will provide zero sequence current for operation of the ground overcurrent elements.

• It should be noted for SLG faults the high Z2 will greatly minimize the amount of resulting 3I0 current such that the ground overcurrent element will have the same limitation for ground fault protection during SLG faults as phase overcurrent current protection in radial configurations.

Ground Overcurrent

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Directional ElementsNegative and Zero Sequence Directional Elements

• The directional elements use the phase angle between the negative or zero sequence voltage and current to determine directionality.

• Negative sequence voltage and current quantities have the advantage of the following:• Immune to mutual coupling of nearby lines.• More sensitive than 3I0 in some cases.

• In a synchronous machine dominated system the machine inductance phase angle relationship is approximately 90 deg for negative and zero sequence phasors.

• Inverter controls minimize negative sequence current and voltage magnitude.

V2

I2

V0

I0

Forward Fault Reverse Fault

V2

I2

V0

I0

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Directional Elements

Directional Element IBR Issues

• Many inverters suppress negative sequence current and voltage magnitude.

• This prevents proper operation of the negative sequence directional elements from a magnitude and phase angle perspective.

• Can result in a non-operation or misoperation of a directional element.

• The majority of transmission interconnections are via a Wye-Gnd/ Delta connected transformer, thereby providing a zero sequence source for ground directional supervision.

• For IBR applications Zero Sequence may be the best method for ground relay polarization.

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IBR Fault Example 1Single Line to Ground Fault Example

• The system above was subjected to a sustained single line to ground fault, the interconnected PV facility was generating approximately 80 MW at the time of the fault.

• During the event line breakers, CB A, CB 3, and CB 4 tripped isolating the fault.

• 30 cycles later CB 3 high speed reclosed into the sustained single line to ground fault.

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IBR Fault Example 1Single Line to Ground Fault

Quinto – Westley Switching Station 230kV During SLG Fault

Solar PV Fault Contribution

Fault Contribution to

Westley

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IBR Fault Example 1Single Line to Ground Fault

Quinto – Westley Switching Station 230kV During SLG Fault

I1= (259A)I2 = (47A)

3I0 = (195A)

I2 current = 21% of I1 current and 24% of the zero-sequence current, Indicating the PV inverters are limiting their negative sequence current injection.

Solar PV Fault Contribution

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• Fault Occurs on Midway –Smyrna 115kV line.

• CB 122 trips on 67G (Inst) element .

• Forming an island with interconnected generation.

• Island terminates in 0.613 sec.• Approx. 100MW PV on-line

Midway Smyrna 115kV Line Fault

SLG B

Phase Fault

CB 472

CB 122

Midway

CB 112

Smyrna

Olive Sw Sta

CB Normally

Open

Distribution Sub

DTT

20MW 20MW

50MW 20MW

20MW 20MW

IBR Fault Example 2

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Smyrna 115kV Voltage

Smyrna Line Current Contribution

Midway Smyrna 115kV Line Fault

Relay Gnd directional element Z2F operated correctly

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Smyrna Phasors

Phase Voltage and Currents

Sequence Voltage and Currents

In this case the inverters provided adequate negative sequence current allowing for proper negative sequence element operation

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Distance Elements

• Phase and Ground Distance relay measure the voltage and current for fault determination.• Are less susceptible to load encroachment. • For a two terminal line the distance element setting is based on line impedance.• To add security most modern distance elements are supervised with phase and ground fault detectors.

• Phase Distance -Typical fault detector setting is above load and low enough to pick-up for all in-section faults.

• The high Z2 that affects phase and ground overcurrent protection will result in phase/ground distance limitations.

• For unbalanced faults the high Z2 impedance will result in higher apparent impedance resulting in under-reach of the distance elements.

• Lack of current results in lowering of fault detector decreasing security of the element. • Low current may also be below the setting range of the relay.

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Distance Element

Relay Element Fault Type Voltage Current1 A phase to B phase VA – VB 1A - 1B2 B phase to C phase VB – VC 1B – 1C3 C phase to A phase VC – VA 1C – 1A

Relay Element Fault Type Voltage Current1 A phase to ground VA 1A + 3I0k2 B phase to ground VB 1B + 3I0k3 C phase to ground VC 1C + 3I0k

k= (Z0-Z1)/3Z1

Phase Distance voltages and currents applied to distance relays for multi-phase faults. Lowering of currents could affect distance element sensitively.

Ground Distance voltages and currents applied to distance relays for multi-phase faults. Reduction of 3I0 and phase current may affect ground distance element sensativity.

I11

I12

Z1G

1 Z1

L*m

Z1L*

(1-m

) Z1

G2

Z2L*

m I2

1 =0

Z2G

1

I22

Z2L*

(1-m

) Z2

T2

Positive Sequence

Negative Sequence

Rfault

G

Inverter System

Z1T1

Z1T2

Z1G

2

Z2T1

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IBR Protection IssuesMitigation for IBR protection issues Apply current differential protection.

• Requires high speed communication, can be expensive.• Difficult to apply on multiterminal lines.

Apply Zero sequence polarization• Influenced by mutual coupling of nearby lines, resulting in a misoperation.• May not operate in some cases, (stiff sources on long lines).• PG&E has modified setting templates to enable Zero sequence polarization near IBR

generation.

Install DTT from the strong Source to the IBR generation terminal.• DTT is the primary method for removing IBR generation from a faulted line.

Require IBR to produce I2 current. • Would assist with proper operation of ground directional elements, may not help with phase protection due to low phase fault current.

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IBR Low Fault Duty IBR Generation has a low Short Circuit Characteristic

Due to the projection of 100% renewable in the PG&E system by 2045 there could be issues with low fault duties.

To evaluate the effect of high IBR penetration all thermal generation in the PG&E area was converted to IBR type generation.

• Converted all thermal and nuclear plants into IBR type generation.• Hydro was left unchanged.• 14GW of generation was converted.• Used Aspen Voltage Source in Current limit mode.• PG&E is part of WECC, interconnections with other utilities left unchanged for Example 1

• SCE (Southern Ca Edison) contribution was modified in Example 2.

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IBR Protection Issues

Current Limit at 1.1pu Z2 and Z0

at 9999

Example of Machine to IBR Conversion

• Inverter Based Generation fault characteristics PV (photovoltaic) or Type 4 Wind Turbine

• Present Aspen Model for current limited generation.

• Enter the controlled fault current magnitude, in the current limit section. typically 1.1 to 1.2 pu).

• Set the generation impedances as shown. Z1=0.02, Z0 = 9999, Z2 = 0.02

• Note: Recent data suggests Z2 = 9999 this should be verified with the inverter manufacture.

• Set “Enforce current limit A” in the Preferences>Fault Simulation settings.

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Low Fault Duty2882 busses were faulted for 3 phase and SLG faults.

SCE (Southern Ca Edison) Interconnection Unchanged.

SLG fault statisticsAverage Median Min Number of Busses

Total Busses -1.7% -0.6% -52.3% 2882> 20% >10-20% >5-10% <5%

500kV -4.1% -2.4% -17.6% 65 0.00% 12.31% 20.00% 67.69%

230kV -3.0% -1.8% -23.3% 421 0.71% 6.65% 3.56% 89.07%

115kV -2.4% -1.1% -49.4% 1042 0.96% 2.69% 7.77% 89.16%

60/70kV -0.6% -0.4% -52.3% 1349 0.00% 0.07% 0.22% 99.70%

3 Phase fault statisticsAverage Median Min Number of Busses

Total Busses -0.7% -0.1% -32.6% 2882> 20% >10-20% >5-10% <5%

500kV -2.1% 0.5% -20.4% 65 9.23% 0.00% 6.15% 84.62%

230kV -1.3% 0.2% -31.2% 421 1.19% 7.36% 3.56% 89.31%

115kV -1.1% 0.0% -32.6% 1045 0.57% 3.73% 8.04% 87.66%

60/70kV -0.1% -0.1% -20.9% 1349 0.07% 0.22% 0.15% 99.48%

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Low Fault Duty

3 phase fault statisticsAverage Median Min Number of Busses

Total Busses -0.8% -0.1% -35.0% 2882> 20% >10-20% >5-10% <5%

500kV -2.7% 0.4% -17.9% 65 0.00% 15.38% 7.69% 76.92%

230kV -1.4% 0.1% -31.0% 421 1.19% 7.36% 3.56% 87.89%

115kV -1.2% -0.1% -35.0% 1042 0.58% 3.84% 8.25% 87.14%

60/70kV -0.2% -0.2% -20.9% 1349 0.07% 0.22% 0.15% 99.56%

SLG fault statisticsAverage Median Min Number of Busses

Total Busses -1.9% -0.7% -51.7% 2882> 20% >10-20% >5-10% <5%

500kV -6.4% -3.0% -23.8% 63 9.52% 9.52% 25.40% 55.56%

230kV -3.4% -2.2% -27.5% 421 1.66% 5.70% 12.59% 80.05%

115kV -2.7% -1.3% -51.7% 1042 0.96% 3.26% 8.35% 87.43%

60/70kV -0.7% -0.5% -13.2% 1349 0.00% 0.07% 0.22% 99.70%

2882 busses were faulted for 3 phase and SLG faults. SCE (Southern Ca Edison) interconnection modified to simulate high pen IBR.

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Low Fault Duty Conclusions• The low fault duties are localized to the generation busses that

were converted.

Mammoth F

Mammoth E

Mammoth D

Whistler E/F

North Star 2

North Star 3

Mammoth E 115kV

Large Gens Converted to IBR (2232 MVA)

Large Gens Converted to IBR (2232 MVA)

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Low Fault Duty Conclusions• The low fault duties are localized to the generation busses that

were converted.

Before  After

Bus Name kV 3LG (A)  LL (A)  1LG (A)  3LG (A)  LL (A)  1LG (A) 3LG 

%DIFFLL 

%DIFF1LG 

%DIFF

MAMMOTH D 230 52,584 45,458 51,684 45,037 37,991 46,225 -14.4% -16.4% -10.6%

MAMMOTH E 230 52,603 45,475 51,703 45,046 37,999 46,237 -14.4% -16.4% -10.6%

MAMMOTH F 230 52,550 45,429 51,652 45,011 37,968 46,195 -14.3% -16.4% -10.6%

MAMMOTH E 115 45,500 39,368 47,990 46,424 36,950 45,812 2.0% -6.1% -4.5%

WHISTLER BE 230 13,519 11,675 11,042 13,804 11,242 10,802 2.1% -3.7% -2.2%

WHISTLER BF 230 13,626 11,767 10,976 13,913 11,332 10,740 2.1% -3.7% -2.2%NORTH STAR 3 230 12,691 10,959 9,763 12,937 10,579 9,573 1.9% -3.5% -2.0%

NORTH STAR 2 230 12,631 10,907 10,165 12,874 10,530 9,960 1.9% -3.5% -2.0%

• Fault duty decrease becomes less pronounced a couple of busses away from the modified generation.

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Conclusions

• Use current differential protection on generation tie lines and adjacent lines that are in a radial configuration with IBR.

• Apply Direct Transfer Trip (DTT) from the strong source terminal to the week generation terminal.

• Modify ground polarization method from V2/I2 to Vo/I0 on lines associated with heavy IBR generation.

• Low fault duty is a localized phenomena and not as much as a grid wide issue for the foreseeable future.

• IBR based generation presents challenges to traditional protection schemes, however the challenges can be overcome with the knowledge of IBR fault characteristics.

• Ongoing challenges• There needs to be better fault simulation models for IBR generation.

• IEEE/EPRI working group C24 is trying to address the issue.• Inverter manufactures need to be more forthcoming in supplying inverter

fault current characteristics for fault studies.• More standardization on IBR fault characteristics so they can be modeled

effectively, efficiently, for proper protection scheme settings and applications (ierequire a level of I2 injection during fault conditions)

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Questions & Comments???