Technical Standards and Specifications · interface, the embedded generator and/or system and the utility distribution network with respect to embedded generation. The specification

- Technical Standards and

Specifications -

Technical Standards and Specifications

Training on technical standards and specifications:

• content of NRS 097 series,

• the wiring code and wiring standards,

• SANS 10142-1-X (currently under development),

• the SA Renewable Power Plant (RPP) Grid Code and

• other appropriate ranges of standards including

international standards (e.g. IEC).

Overview: Technical Standards

3

Loads

Off and on Earth leakage

=≈

M

M

Solar Load

Control

Municipal Network

1

2

3 4

15

6

7

8 9

10 11

13

14

PE/PEN

12

5

Overview: Technical Standards

• South African Documents

– NRS 097

– SANS 10142-1-X

– RPP Grid Code

– NRS 052 / SANS 959

– NRS 048

• International Documents

– IEC 62109: Safety of power converters for use in

photovoltaic power systems

NRS 097-1

Part 1: Distribution standard for the interconnection of embedded

generation

– To be based on Eskom standard

– (Document number: 240_61268576)

• Still not developed

• >100kVA

• SA Grid Code for Renewable Power Plants (RPP Grid Code)

– Eskom document contains more than the minimum

requirements in the RPP Grid Code

NRS 097-2• Grid interconnection of embedded generation

• Part 2: Small-scale embedded generation

• The specification sets out the technical requirements for the utility interface, the embedded generator and/or system and the utility distribution network with respect to embedded generation. The specification applies to embedded generators and or embedded generator systems smaller than or equal to 1000 kVA connected to low-voltage networks.

– Section 1: Utility interface

– Section 2: Embedded generator requirements. (To be developed in the future.)

– Section 3: Utility framework.

– Section 4: Procedures for implementation and application. (To be developed in the future.)

NRS 097-2-1

• Grid interconnection of embedded generation

• Part 2: Small-scale embedded generation

• Section 1: Utility interface– Technical requirements for a generator to connect to the utility

network

– Not an inverter specification

“Device Independent”

– Not a generator specification

Interface Document

– Describe the requirements at the utility interface

Overview: NRS 097-2-1

• Interface

9

Loads


=≈

M

M

Solar Load

Control

Municipal Network

1

2

3 4

15

6

7

8 9

10 11

13

14

12

5

NRS 097-2-1

• Connected to LV (<1 kV)

• Edition 1 <100 kVA

• Edition 2 <1000 kVA

• Several changes

– Aligns with RPP Grid Code as far as possible

– Influenced by international developments

NRS 097-2-1 / RPP Grid Code

• Size and balancing information

– Category A1: 0 – 13,8 kVA

– Category A2: >13,8 kVA – <100 kVA

• Central disconnection

– Category A3: 100 kVA – <1 MVA

• Controllability (4.1.1.15)

• Ramp-up after abnormal conditions

11

NRS 097-2-1

• Equivalent International Documents

– IEC 61727

– IEEE 1547

– EN 50438

– VDE-AR-4105

– G83 / G59

NRS 097-2-1

• Three clauses:

4.1 Utility compatibility

4.2 Safety and protection

4.3 Metering

4.4 UPS with embedded generation

13

NRS 097-2-1

• Clause 4.4 removed for Edition 2:

– 4.1.1.13 Any UPS/generating device that operates in parallel

with the grid may only connect to the grid when it complies fully

with the requirements of this part of NRS 097. This includes UPS

configurations with or without EG.

• NOTE The requirement is applicable irrespective of the duration of

parallel operation.

14

NRS 097-2-1: Utility Compatibility

• General Clauses:

– general requirements

– sets the basic parameters

– basic system compatibility

– power quality compatibility

– type approval

– size allowed

– utility approval

– fault level

– Installation requirements

• Ref SANS 10142-1 and -1-2

• Maximum DC voltage - 1000 V (1500 V)

15


• In accordance with SANS 10142-1 and/or 10142-1-2, all generators

shall be wired permanently.

• Standby-generators are covered by SANS 10142-1.

– Change-over switch

16

NRS 097-2-1

• Summarise as:

– What to expect?

– What is allowed?

– What to do?

17

=≈

=≈

=≈

CONTROL

What to Expect?

• Voltage

– South African LV range

– Check connection

• Frequency

– 50 Hz ±2%

– RPP Grid Code ride-through requirements

18

=≈

What to Expect?

• Power Quality

– Take note of NRS 048-2 compatibility levels

– Generator must be able to withstand these levels

continuously

– Protect itself should levels exceed these

19

=≈

What to Expect?

• EMC / Mains signalling

– Fail-safe

20

=≈

What to Expect?

• Fault Level

• Short-circuit ratio

– Documentation and nameplate

– Design

– Type testing

21

=≈


• Reference Source Impedance and Short-Circuit Levels

– IEC 60725: 0,4 + j0,25 Ω

– Annex C (p41):

– Z_source = 1,05 + j 0,32 Ω

– I_SC = 210 A

– S_SC = 146 kVA (three-phase)

• NOTE Use with caution, based on published international

values and simulations only.

22


25

0

0.05

0.1

0.15

0.2

0.25

0.3

0.35

0.4

0.45

0.5

0 50 100 150 200 250 300 350 400 450 500

FA

UL

T L

EV

EL

[K

A]

LV LINE LENGTH [M]

125kVA 25mm2 (1ph FL [kA]) 315kVA 400mm2 (1ph FL [kA]) 210A

What Allowed?

• Inject current - not voltage

– Voltage control (future requirements) may lead to instability

• Synchronise

• Operate within trip limits

• No islanding

– Out of phase reclosing

26

=≈

What Allowed?

• QOS contributions

– Flicker (p13)

• Short-term flicker severity limit Pst = 0,35

• Long-term flicker severity limit Plt = 0,30

– 3% Voltage change limit

– Utility to manage by appropriate planning

27

=≈

What Allowed?


– Voltage unbalance (p13 to 14)

• 4.6 kVA difference between phases limit

• Three-phase generators: 0.2% limit

• Grid Code limits difference between phases

– 4.6 kVA (any size up to 1 MVA)

28

=≈

What Allowed?


– Harmonics and waveform distortion (p15)

– IEC 61727

• IEEE 1547

• IEEE 519

– Up to the 60th

29

=≈


• p15

• Also refers to NRS 048-4

30

Harmonic order (h) h<11 11≤h<17 17≤h<23 23≤h<35 35≤h

Percentage of rated current

(Odd harmonics)

4,0 2,0 1,5 0,6 0,3


(Even harmonics)

1,0 0,5 0,38 0,15 0,08


(Inter-harmonics)

0,1 0,25 0,19 0,08 0,03

Total Demand Distortion = 5%

NOTE 1 Even harmonics are limited to 25 % of the odd harmonic limits

NOTE 2 Inter-harmonic are limited to 25 % of the odd harmonic limits and adjusted for the 200

Hz band measurement required by IEC 61000-4-7, except for the lower frequencies where the

flicker contribution is more likely.

NOTE 3 Total Demand Distortion = Total Harmonic Distortion

Harmonic Examples

-400

-300

-200

-100

0

100

200

300

400

0.000 0.005 0.010 0.015 0.020

Harmonic Voltage

31

Harmonic Current Examples

0

1000

2000

3000

4000

5000

6000

7000

8000

9000

10000

0

0.5

1

1.5

2

2.5

3

3.5

4

4.5

5

2016/05/07 00:00 2016/05/07 04:48 2016/05/07 09:36 2016/05/07 14:24 2016/05/07 19:12 2016/05/08 00:00 2016/05/08 04:48 2016/05/08 09:36 2016/05/08 14:24

3rd Harmonic Current as Percentage of Maximum Fundamental

I_1 I_2 I_3 P_TOTAL

33

10 minute values

Harmonic Current Examples

-1000

0

1000

2000

3000

4000

5000

6000

7000

8000

9000

0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

2016/05/07 00:00 2016/05/07 04:48 2016/05/07 09:36 2016/05/07 14:24 2016/05/07 19:12 2016/05/08 00:00 2016/05/08 04:48 2016/05/08 09:36 2016/05/08 14:24

11th Harmonic Current as Percentage of Maximum Fundamental

I_1 I_2 I_3 P_TOTAL

35

What Allowed?


– DC injection (p14)

– 1-minute average d.c. current injected ≤ 0,5 % of

rated a.c. output current

• under any operating condition.

36

=≈

What Allowed?

• Power factor

• Power factor requirements updated

– A1 and A2 pf > 0.98

– A3 pf > 0.95

– (If required, specifics may be requested)

37

=≈

What Allowed?


– IEC 62578 (to be removed)

• May require filtering (e.g. separate transformer)

– SANS/IEC 50065-1

• 3 kHz to 148,5 kHz

• Unintentional

• To start at 30 kHz (WG recommendation)

38

=≈

What Allowed?


– SANS 211 (CISPR11)

• From 148,5 kHz (not 150 kHz)

• Class B Group 1

• Radiated and Conducted (unintentional)

39

=≈

What Allowed?


– Existing and new PLC-based communication systems

have preference

• SSEG to fix if and when problems arise

40

=≈

What to DO?

• Safety

– SANS/IEC 62109-1 and IEC 62109-2

• Ensure Anti-islanding

• Redundancy

41

=≈

CONTROL

What to DO?

• Automatic disconnection for abnormal conditions:

– network voltage or frequency out-of-bounds conditions

– loss-of-grid conditions

– d.c. current injection threshold exceeded (per phase)

– and residual d.c. current (phase and neutral currents

summated)

42

=≈

CONTROL

NRS 097-2-1: Safety and protection

• Overvoltage, under-voltage and frequency (including

voltage-ride-through)

• Sub-categories A1 and A2

– RPP Grid Code may override

• Sub-category A3 - RPP Grid Code applies

– Same as Category B

• Network and System control need not intervene

43


• Sub-category A1 and A2: Safety disconnect requirements

• Abnormal Voltages

Voltage range

(at point of connection)

Maximum trip time

S

V < 50 % 0,2 s

50 % ≤ V < 85 % 10 s

85 % ≤ V ≤ 110 % Continuous operation

110 % < V < 115 % 40 s

115% ≤ V < 120% 2 s

120 % ≤ V 0,16 s

NOTE If multi-voltage control settings are not possible, the more

stringent trip time should be implemented, e.g. 2 s between 110%

and 120% of voltage.


• Category A: Safety disconnect requirements

• Abnormal Frequency

f < 47 HzDisconnect

0,2 s

f > 50.5 HzInstantaneous

output power ->

PM

f > 50.5 HzReduce/ increase

linearly as a

function of PM

f > 50.5 HzSA: 50% droop

f > 51,5 Hz > 4sTrip within 0,5 s


4.2.2.3.4 Relaxation for non-controllable generators

• Randomly disconnect between 50,5 Hz and 51.5 Hz

• 0,1 Hz steps

• Uniform distribution per manufacturer

What to DO?




– d.c. current injection threshold exceeded (per phase)

– and residual d.c. current (phase and neutral currents

summated)

47

=≈

CONTROL

Anti-Islanding-Additional

• What is an island?

– Section of network

– Disconnected from main grid

– Generation continues to supply load

• Implies - balance between generation and load

• NOTE: loss-of-grid and anti-island used interchangeably

48


4.2.2.4 Prevention of islanding

• Cease to energise the network within 2 s

• NOTE Prevention of islanding measures is only considered on the

embedded generator side, i.e. no utility installed anti-islanding

measures are considered.

– Utility to consider ARC settings!


4.2.2.4 Prevention of islanding

• Passive methods

– Three-phase voltage detection and shall be verified by an AC

voltage source.

– Not be the sole method to detect an island condition.

• At least one active island detection method implemented

– Needs interaction with EG

– IEC 62116: Anti-islanding test

What to DO?




– d.c. current injection threshold exceeded (per

phase)

– and residual d.c. current (phase and neutral

currents summated)

51

=≈

CONTROL

What to DO?

• Ensure synchronisation (p18)

– Network voltage stable for 60s

– Ramp up at 10% per minute OR

– Random reconnection from 1 to 10 minutes

• Only automatic synchronisation allowed

52

=≈

CONTROL

What to DO?

• Dip ride-through (X1-type dips)

• OR

• Category B and C curve (A3)

53

=≈

CONTROL


• Voltage ride-through: Sub-category A1 and A2

54


130%

125%

120%

115%

110%

100%

95%

90%

85%

80%

75%

70%

65%

60%

55%

50%

45%

40%

35%

30%

25%

20%

15%

10%

5%

0%

X1

Y

Disconnect 10s

150 600 3000 ms

Disconnect 0.16s

Disconnect 2.0s

Disconnect 40s

Disconnect 0.2s

55

20s

110%

120%

150 600 3000 ms

40%

0%

60%

Y

Z1

SX1

X2

Z2

T

70%

80%

90%

Area A

Area B

Area C

Area D


• Ride-through requirements (Also RPP Grid Code)

– Category A3

– Same as category B (and C excluding Area D)

What to DO?

• Power factor control (> 100 kVA)

• Capability required

57

=≈

CONTROL


4.1.11 Power factor

• Controllable EG

– Towards unity at PoC

• Utility may request characteristic curve

– Default is unity

58


• Power factor control

• Often requires capacitors

• Separate vs. integrated

• May need detuning

– Harmonics

– Switching transients

• Discussion and agreement between EG owner and utility

59


• Disconnection device

• Compulsory

– Integrated or stand-alone

• Stand-alone may be suitable, e.g.:

– All EG installations larger than 30 kVA shall have a central

disconnection device.

– For customers' own load in isolated operation.

• Operate under all network conditions

– E.g. future fault level

– EG Owner responsibility

• Power quality immunity

– over voltages, harmonics etc.

60


• Reliability of Disconnection Device:

• Fail SAFE:

– A failure within the disconnection device shall lead to disconnection

of the generator from the utility supply and indication of the failure

condition.

– A single failure within the disconnection switching unit shall not lead

to failure to disconnect. Failures with one common cause shall be

taken into account and addressed through adequate redundancy.

– The disconnection device shall disconnect the generator from the

network by means of two series connected robust automated load

disconnect switches.

– Both switches shall be electromechanical switches.

– Each electromechanical switch shall disconnect the embedded

generator on the neutral and the live wire(s).

61


• The fault current breaking capacity of each disconnecting switch

shall be appropriately sized for the application.

• Any programmable parameters of the disconnection switching unit

shall be protected from interference by third-parties, i.e. password

protected or access physically sealed.

• The network and system grid protection voltage and frequency relay

for the central disconnection device will be type-tested and certified

on its own (stand-alone tested).

62


DGSL• Dead Grid Safety Lock

• Dr Hendri Geldenhyus

– Dr Johan Beukes

63


4.2.3 Emergency personnel safety

• No requirements for emergency personnel safety (e.g. fire brigade)

existed at the time of publication. It is expected that such issues will

be dealt with in other documents, e.g. OHS Act, SANS 10142-1.


4.2.4 Response to utility recovery

• Always synchronise (cfg. 4.1.12)

• Stable voltage and frequency: 60s

• Non-controllable generators

– Select reconnection time: 1 min to 10 min

– No more than 2% within 10s

• Controllable generators

– Reconnect at 1 min

– Ramp up at 10% per minute


4.2.5 Isolation

• In line with SANS 10142-1 (as amended), each energy source should have its own, appropriately rated, isolation device.

• Maintenance of EG

– Note internal requirements not covered by NRS 097-2-1

• SANS 10142-1/-1-2 developments will supersede

• Rated appropriately in accordance with SANS 60947-2

• For dedicated suppplies

– A similar disconnection device

– Lockable and accessible by utility

– Utility owned

How to earth a generator


4.2.6 Earthing

• To be finalised for SANS 10142-1-2

– Floating DC preferred

• B.3.2 Earth electrode

• B.3.2.1 All alternative systems shall have an own earth electrode connected to the consumer’s earth terminal and shall comply with 7.12.3.1.1 in SANS 10142-1:2012.

• B.3.2.2 Embedded generators need not have their own earth electrode in accordance with SANS 101421, but an own earth electrode is preferred.

69

DC: TN-S

TN-S d.c. systemFloating d.c.Protective earth

L+

L-

PE

Source(s) Installation

TN-S


• Earth leakage:

• As per IEC 62109-2

• RCD that can detect smooth dc (without zero crossings)

– Avoid nuisance tripping (i.e. higher leakage currents)

• RCD type B according to IEC/TR 60755, amendment 2

• Unless dc can be prevented completely

– E.g. transformer between dc and ac


4.2.7 Short-circuit protection

• In accordance with SANS 10142-1 and SANS 10142-1-2.

• Supply EG short-circuit characteristics to utility


4.2.8 Maximum short-circuit contribution

• In order to limit the fault level changes in low voltage networks and

allow coordination of fault levels with the utility, no generator will

exceed the following fault level contribution:

a) for synchronous generators: 8 times the rated current;

b) for asynchronous generators: 6 times the rated current; and

c) for generators with inverters: 1 times the rated current.

• Check short-circuit ratings of all equipment

– Note potential impact on adjacent customers


4.2.9 Labelling

• SANS 1186-1

• Upstream DBs

-

-


4.2.10 Robustness requirements

• According to 4.2.2.1, all SSEG shall comply with safety

requirements in accordance with SANS/IEC 62109-1 and

IEC 62109-2.

• NOTE This section will be expanded in future revisions.

Utility Staff Safety: MV

• MV Process

• Open

• Isolate

• Test

• Earth

– Both sides

• Work

75

Utility Staff Safety: LV

• LV Process

• Open

• Isolate

• Test

• Earth

– Not possible

• DGSL

• Work

76

Disconnecting Device Layout

Contactor 1 Contactor 2

Auxiliary Relay

The DD comprises of:

Auxiliary Relay: Double pole NO contacts

Contactor 1 and 2: NO contacts to break all phases and Neutral. Single auxiliary NC contact

Source: Dr Hendri Geldenhuys (Eskom)

NRS 097-2-1: Metering

• Meter remains property of utility

• Metering will comply to SANS 474/NRS 057 and SANS

473/NRS 071

• Smart meters: NRS 049

78


• Signage may also be required for metering (meter readers)


• Single quadrant meter (standard meter)

• Recommended upgrade to four quadrant

• Note confusion on use of “Nett metering”

80

kWhkWh

EG L

U

~

DB

Net

meter


• Two or four quadrant meter

• Two options

81

kWhkWh

EG L

U

~

DB

kWhkWh

Consumption

meter

Embedded

generation

meter

kWhkWh

EG L

U

~

DB

kWhkWh

Net

meter

Embedded

generation

meter

NRS 097-2-1 Summary

• Interface document

• Device independent

4.1 Utility compatibility

4.2 Safety and protection

4.3 Metering

82

NRS 097-2-2• Embedded generator requirements

– Type testing - proving compliance to NRS 097-2-1

• Draft

• References to IEEE 1547.1

• Testing houses in SA – None

• SABS - no facilities

• Processing and compliance monitoring

• Database

83

NRS 097-2-3

• Simplified utility connection criteria for low-voltage connected generators

• For use by utilities

– Customers can establish what would be easy to connect, e.g. smaller than 25% of ADMD/Breaker size

– Maximum size as a function of cable parameters and distance from transformer

• Flowchart to consider connection without detailed studies

• When SSEG connection request complies with simplified checks, can be connected

– Allows for larger SSEG connections, pending detailed studies by utility

• Principle of fairness

– 30% of 50% of customers can be accommodated

NRS 097-2-3

• Type-test certified to NRS 097-2-1.

• Simplified connection: limited to 350 kVA.

• The maximum permissible generation size of an individual LV

customer is dependent on:

– the type of LV network, i.e. shared or dedicated.

– the customer’s notified maximum demand (NMD) (i.e. circuit-

breaker rating).

• Additional requirements linked to the size of the MV/LV transformer

and maximum loading of the associated MV feeder are discussed

this section of NRS 097-2.

89

NRS 097-2-3

• The LV fault level at the customer point of supply should be greater

than 210 A.

– NOTE Details of the selection of the 210 A fault level is

discussed in annex C of NRS 097-2-1:Ed2.

• If the criteria in this standard are not met -> more detailed studies

are required.

• Utilities may modify the criteria, or add additional criteria, to meet

their specific requirements considering their network characteristics.

90

NRS 097-2-3: Basis for the calculations

NOTE 1 The proposed criteria in this section of NRS 097-2 have been

guided by

– the approaches used in other countries and utilities, as informed

by work within Cigre, and specifically Cigre working group C6.24.

The intention is to adopt best practice as already applied in other

utilities that have considerable experience with LV connected

generators; and

– the application of specific technical criteria on models that

represent typical South African LV networks.

• NOTE 2 It is intended that the criteria will be enhanced and revised

as more detailed studies are performed in the future and that the

industry can learn from the application of these criteria.

91

NRS 097-2-3

• The technical limits that constrain the amount of generation are as follows

a) thermal ratings of equipment (lines, cables and transformers) may not be

exceeded;

b) LV voltage regulation should be within the limits specified in NRS 048-2 (LV

voltages at the customer point of supply should be within ± 10 %);

c) the maximum change in LV voltage (due to voltage drop/rise in the MV/LV

transformer and LV feeders) due to embedded generators is limited to 3 %.

– This is a common international practice where the generation is

variable.

– From a voltage change perspective, it does not matter how much of the

generation is consumed locally or fed back into the network.

d) islanding on the utility network is not allowed;

e) the fault level at the customer point of supply should be greater than 210 A,

or the minimum fault level at which the generator is rated.

92

NRS 097-2-3

• The application of the limits given in 4.6.2 resulted in the following proposed

criteria:

a) Voltage rise on LV feeders should be limited to a maximum of 1 %. This

value is informed by the NRS 048 voltage limits, MV voltage control

practices and the MV/LV transformer voltage ratio and tap settings (see

table 4).

b) Voltage rise across the MV/LV transformer should be limited such that the

NRS 048-2 voltage limits are not exceeded (see table 5). The maximum

generation connected to a MV/LV transformer is limited to 75 % of the

transformer rating understanding that this may result in overvoltage

problems on LV feeders where there is further voltage rise. The 75 % limit is

hence high but in reality the net flow through the transformer into the MV

network is expected to be significantly less due to the customer loads. A 75

% limit will also ensure that the transformer will not be overloaded during

periods of maximum generation and minimum loading.

93

NRS 097-2-3

c) The individual customer limit of 75 % of NMD on dedicated LV

feeders is informed by the MV/LV transformer limit of 75 %. This

approach provides customers with equitable access to the

available generation capacity as limited by the MV/LV transformer

rating. It will also ensure that service cables will not be overloaded

under conditions of maximum generation and low loading.

d) The dedicated LV feeder minimum size is based on a maximum

voltage rise of 1 % (figure 3 and figure 4). The 1 % value is in

accordance with table 4.

94

NRS 097-2-3

e) The individual customer limit of 25 % of NMD on shared LV feeders is

informed by an analysis of typical LV feeder designs whereby the

individual generator size was scaled as a function of the design ADMD

and the generation penetration level (percentage of customers that

install a generator).

a) The voltage rise and change in voltage were calculated

assuming that the installed generation is reasonably

balanced.

b) An individual limit of 25 % of NMD will typically support a

penetration level of 30 % to 50 %, which is considered a

reasonable and acceptable compromise between

restricting individual generator sizes versus restricting

penetration levels.

c) It shall be noted that a primary limitation is the maximum

voltage change of 3 %.95

NRS 097-2-3

f) The total generation connected to a MV feeder is limited to 15 % of

the MV feeder maximum loading.

a) This value is informed by practices in the United

States and Europe, and is based on the ratio of

maximum to minimum feeder loading for typical

consumer load profiles.

b) A limit of 15 % will ensure a low probability of reverse

power flow into the MV feeder source, thereby

preventing voltage rise in the MV feeder and reducing

the possibility of an island for operation of MV

switches and protection.

96

NRS 097-2-3

• Calculation of maximum LV voltage rise

• Calculation of maximum generation connected to a

MV/LV transformer

• Worst-case scenario simulations

– High load - high EG generation

– High load - no EG generation

– Low load - high EG generation

– Low load - no EG generation

97

NRS 097-2-3

• Table 1 — Maximum individual generation limit in a

shared LV (400 V/230 V) feeder

99

Number of

phases

Service circuit-

breaker size

NMD

[kVA]

Maximum individual

generation limit

[kVA]

1 20 A 4,6 1,2

1 60 A 13,8 3,68

1 80 A 18,4 4,6

3 60 A and 80 A 41,4 13,8 (4,6 per phase)

NRS 097-2-3

• Figure 3: Dedicated LV feeder maximum generator sizes as a function of

PVC copper cable size and distance

– 1% voltage rise

• Also figure 4: aluminium cable

• Tables 2 and 3 – look-up tables for these figures

101

0

50

100

150

200

250

300

350

400

450

0 50 100 150 200 250 300 350 400 450 500

Ge

n (

kW)

Distance (metres)

(Pf=1)

300 Cu PVC

240 Cu PVC

185 Cu PVC

150 Cu PVC

120 Cu PVC

95 Cu PVC

70 Cu PVC

50 Cu PVC

25 Cu PVC

NRS 097-2-3

4.5 Simplified connection criteria

• Flowchart

103

Research

• Master's student

– Emmanuel Namanya

– Proff Gaunt and Herman

• Thesis: “Voltage Calculation on Low Voltage

Feeders with Distributed Generation”

– May 2014

• NRS 034 (Herman Beta method)

106

Research

80

85

90

95

100

105

110

115

120

0 100 200 300 400 500 600

Vo

ltag

e [%

]

Distance [m]

Voltage Profile

Base Case

107

10%

10%

Research

80

85

90

95

100

105

110

115

120

0 100 200 300 400 500 600

Vo

ltag

e [%

]

Distance [m]

Voltage Profile

Base Case

Base +5%

108

15%

5%

Research

111

0 10 20 30 40 50 60 70 80 90

100

% EG/NMD (Approximate)

Research: Summary

• Recommendation:

– 30% of ADMD (not NMD)

– Approximately15% of NMD

112

NRS 097-2-3 Summary

• Simplified Connection Criteria

• Flowchart

• Basic checks

– Customer size

– Thermal loading of feeder

– Fault level > 210 A

• Total installed capacity as percentage of:

– MV/LV Transformer size

– MV Feeder loading

– Network loading (HV/MV substation)

• If not meet - detailed studies

113

NRS 097-2-3

• What if the connection request does not meet the

requirements?

• A few slides on guidelines for planning processes

• And other aspects to keep in mind

114

General Impact Study

• Loadflow

– Thermal ratings

– Voltage regulation

• Voltage transients

– EG rejection

• Short-circuit studies

– Equipment ratings

– Protection coordination

115

General Impact Study

• Calculation of maximum generation connected to a MV/LV transformer

– Calculation of maximum LV voltage rise

– Calculation of maximum thermal loadings

– Note impact of dc currents

• Worst-case scenario simulations

– High load - high EG generation

– High load - no EG generation

– Low load - high EG generation

– Low load - no EG generation

116

Thermal Ratings

• Thermal ratings

– Typical Urban network

– Maximum load limited by thermal ratings

– Rather than voltage drop

• Loadflow

• Minimum load vs

• Maximum generation

• Reverse power flow possible

– e.g. Weekend mid-day

117

Generation

Load

Max

MinMaxMin

Thermal Ratings

• Thermal ratings

– Depending on location of EG

– Load growth

– Feeder conductor

• Reducing conductor sizes

– Evaluate all corners

• Thermal ratings for:

– Lines

– Cables

– Transformers

118

Generation

Load

Max

MinMaxMin

Data Requirements

• All cable/lines in the modelled area:

– types (conductors)

– length

• Substation transformer

– rating, short circuit impedance, tap changer range,

voltage setpoint

• MV/LV transformers

– including the actual winding ratio/position of off-load

tap changer

119

Data Requirements

• Maximum power output of all SSEG

• Load characteristics

– Profile

– Power factor

120

Protection Impacts

• Increased fault levels

• Reduced reach

• Sympathetic tripping

• Reclosing onto island

• Fuse-saving

121

Increased Fault Levels

• NRS 097-2-1: Ed2

• 4.2.8 Maximum short-circuit contribution

• No generator will exceed the following fault level contribution:

a) for synchronous generators: 8 times the rated current;

b) for asynchronous generators: 6 times the rated current; and

c) for generators with inverters: 1 times the rated current.

• Confirm short-circuit rating from test certificate

• Check short-circuit ratings of all equipment

– Note potential impact on adjacent customers

122

Reduced feeder breaker reach

• Generator also contributes to fault current

• Impedance to end of feeder

• Check feeder breaker settings vs. short-circuit

contribution

123

G

Sympathetic Tripping

• Healthy feeder trip

• Due to fault on adjacent feeder

• EG with high short-circuit current contribution

• Multiple feeders

• Breaker 2 has faster trip

characteristic than breaker 1

• Check breaker trip characteristics

124

G

1 2

Reclosing Onto Island

NRS 097-2-1: Ed2

4.2.2.4.4 An islanding condition shall cause the embedded

generator to cease to energize the utility network within 2 s,

irrespective of connected loads or other embedded

generators.

• ARC times for network in question to be checked

• Minimum ARC time > 2s

125

Fuse-Saving

• Fuse-saving philosophy:

– Feeder breaker first trip very fast

– Delay after first or second reclose to allow fuse to

operate

• EG result in increase in fault current

– Depends on type, size and number of EG

• Fuse may operate quicker

• Lack of coordination

• Need to re-evaluate coordination

126

Summary: Protection Impacts

• Increased fault levels

– Confirm short-circuit rating from test certificate

– Check short-circuit ratings of all equipment

• Note potential impact on adjacent customers

• Reduced reach

– Check feeder breaker settings vs. short-circuit contribution

• Sympathetic tripping

– Check breaker trip characteristics

• Reclosing onto island

– Minimum ARC time > 2s

• Fuse-saving

– Need to re-evaluate coordination

127

NRS 097-2-4

• Procedures for implementation and application

– To be developed

• Application forms and processes

• Database requirements

– keeping track of installations

128

NRS 097-2-4

• Some considerations (from NRS 097-2-1)

• ANNEX A:

• NOTE The customer is advised to contact the utility to discuss potential further connection requirements.

• A.1 The following requirements shall be specified in tender invitations and in each order or contract:

– whether all power quality parameters shall be measured at the POC

• A.2 The following requirements shall be agreed upon between the customer and the utility:

a) whether the EG shall be type approved

b) whether the EG may control the voltage

c) the power factor limits

129

Subtleties

• Renewable Power Producers

– Point of Connection

• Embedded Generators

– Generator terminals

– Point of Connection

• Safety aspects

NRS 097-2-4

• Significant work to be done

• AMEU / SALGA has put together resource pack

131

Compulsory Standards

• Department of Labour

– Determined by Minister

• OHS Act

• Electricity Installation Regulations

• SANS 10142-1

132

Compulsory Standards

133

SANS 10142-1Clause 7.12

• 7.12.1.1 Subclause 7.12 applies to an installation that incorporates alternative supplies intended to supply, either continuously or occasionally, all or part of the installation with the following supply arrangements: Amdt 6

• a) supply to an installation or part of an installation which is not connected to the main supply of a supplier; Amdt 6

• b) supply to an installation or part of an installation as an alternative to the main supply of a supplier; and Amdt 6

• c) appropriate combinations of the above.

• NOTE 1 Requirements of the supplier should be ascertained before a generating set is installed in an installation connected to the main supply of a supplier.

• NOTE 2 This part of SANS 10142 does not cover the supply to an installation that functions in parallel with the main supply (co-generation). Amdt 6

134

SANS 10142-1

Clause 7.12

• 7.12.1.2 Subclause 7.12 covers, but is not limited to, the following:

• a) generating sets that consist of a combination of an internal

combustion engine or a turbine, and an alternator or a d.c.

generator;

• b) rotary UPS systems (uninterruptible power systems) that consist

of a combination of an electric motor and an alternator, with

batteries as a standby power source for the electric motor, or with

an internal combustion engine or turbine as a standby power source

for the alternator; and

• c) static UPS systems that consist of static inverters with batteries

as the standby power source (with or without bypass facilities).

135

SANS 10142-1

• NOTES:

• SANS 10142-1 still applies to balance of installation

• SANS 10142-1 does have a section on DC installations

– Possibly require more for PV installations

– May be addressed in future by another part of SANS

10142

136

Safety Concerns• Installation deficiencies

– Installation of utility-accessible lock-out breaker (where feasible)

– Such a breaker is not feasible in shared networks

– Dead Grid Safety Lock

– DC fed back into network (possible failure modes of the inverter)

– DC vs. AC breakers and associated derating

• Anti-islanding

– Failure to disconnect when the network is de-energised

– Test for voltage before work commences will safeguard LV personnel

• Re-connection while maintenance in progress (DGSL)

– Failure of the inverter to detect that the network is not energised

– Remains a risk (in shared networks) until LV networks can be earthed

– Earthing at LV requires redesign of LV networks (e.g. providing earthing terminals etc.)

• LV Maintenance Process

– Need to measure after disconnection

– Most voltmeters measure either DC or AC

• Australia – rumours of several PV installations that caused fires at residential homes

• Emergency Personnel, e.g. firefighting

137

2019/03/28

SANS 10142-1-X

• SANS 10142-1-2 has to be read in conjunction with SANS 10142-1 and complied with in full on the balance of the installation.

• SANS 10142-1-2 deal with the installation from the Point of Supply to the embedded generator terminals.

• Proposals indicate that SANS 10142-1-2 will deal with:

– Lightning

– Cable selection

– DC protection

– DC Earthing

138

SANS 10142-1-2

139

Loads


=

≈

M

Scope of SANS 10142-1-2:

From EG terminals to POCM

Includes additional DC

where applicable

Neighbours

M

Lightning /

Surge protection

Earthing

Functional Earthing

• A functional earth connection serves a purpose other

than electrical safety, and may carry current as part of

normal operation.• - E.g. IT equipment, telecoms.

• IEC 60364-5-54: 2007: Low voltage electrical installation –

Part 5-54: Selection and erection of electrical equipment:

Earthing arrangement and protective bonding conductors

140

Earthing of Frames

• Frames to be earthed

• Class II insulation (double)

• PID

– Potential Induced Degradation

– Especially thin-film

– Earthing of DC negative pole

– Inverter manufacturer approval

– Need to disable earth fault detection

141

SANS 10142-1-2: Safety and protection

SANS 10142-1-2

• First letter: relationship of the source of energy to earth:

– T:one or more parts are connected direct to earth; and

– I: all live parts are isolated from earth or one point is connected to earth through impedance.

• Second letter: exposed conductive parts of the Consumer's installation to earth:

– T: exposed conductive parts of Installation connected direct to earth,

– independently of the earthing of any point of the source of energy; and

– N: exposed conductive parts of the Installation are connected direct to the source earth,

– (AC) usually the transformer neutral point.

• Arrangement of the neutral and protective conductors:

– C: supply and installation: single conductor;

– S: supply and installation: separate conductors;

– C-S: the neutral and protective functions on the incoming supply are combined in a single conductor and in the Consumer's Electrical Installation are serviced by separate conductors.

Earth Fault Detection

148

• IET CoP (Code of Practice)

Earth fault monitoring

149

Inverter Ground-Fault Detection “Blind Spot” and Mitigation Methods, Greg Ball et al, Solar America Board for Codes and Standards

• Fused GFDI not recommended• Ground Fault Detector and Interruptor

Cable selection

• The maximum voltage value (VDC-max) shall be calculated as follows:

– Voltage (VDC_max) = VOC_STC x 1.15

• The continuous or maximum current, Imax, is defined as 1.25 multiplied by Isc of the string.

– Current (IDC_max) = ISC_STC x 1.25

• Earthing cabling: the same rating!

150

Earthing wiring

• 6 mm2 minimum

• From SANS 10142-1

151

SANS 10142-1-2: Summary

1. Regulatory requirements

2. Embedded generator certification

3. Protection

1. Over current protection

2. RCD for personal protection requirements.

3. RCDs for DC leakage and DC earthing protection

4. Earthing of Neutrals and Protective earthing requirements

5. “Embedded” metering

1. Not covered

6. Isolation and Disconnection

1. Utility accessible isolator

2. Fireman switch for generator output (not required)

3. DGSL

152

SANS 10142-1-2: Summary

7.Monitoring and control

1.There might be requirements related to utility or third party

monitoring and control of the EG.

8.Interlocking protection

9.Islanding operation (refer back to SANS 10142-1)

10.Certification tests

1.Anti islanding

2.Synchronisation

3.Neutral to protective earth insulation test

11.EG-COC

1.Capacity approval limits

2.Proforma COC

12.Registered person(s)

153

Technical Standards and Specifications

Questions?

155