td-2306b-002 distributed generation protection requirements
TRANSCRIPT
Utility Bulletin: TD-2306B-002 Publication Date: 11/15/2017 Rev: 6
Distributed Generation Protection Requirements
PG&E Public ©2017 Pacific Gas and Electric Company. All rights reserved. Page 1 of 12
SUMMARY
The protection requirements for connecting new Distributed Generation (DG) have been modified to reduce the need for Direct Transfer Trip (DTT) schemes which are costly to employ and difficult to manage.
Level of Use: Informational Use
AFFECTED DOCUMENT
Distribution Interconnection Handbook (DIH)
TD-2306B-001, Interconnecting Large 2-20MW Generation Systems
TARGET AUDIENCE
Employees involved with generation interconnection on electric distribution circuits.
DEFINITIONS
Certified Inverter – For the purposes of this document it is an inverter that has been “Certified” per UL 1741 or UL 1741A to trip in 2 seconds or less after the formation of an unintended island.
DG; Distributed Generation – Electric power producing devices or equipement,not directly connected to the bulk electric system, includes both generators and electric storage devices.
Line Section – Defines the zone of protection for the DG in which it is expected to detect and trip for faults and is bounded by a 3 phase fault interrupting device. .A given line section or sections could include multiple zones of protection.
Minimum load – The absolute minimum load that is based on a years’ worth of load data. For solar generating facilities with no battery storage daytime load will be used (10 am to 4 pm for fixed panel installations and 8 am to 6 pm for solar generating facilities with tracking systems).
WHAT YOU NEED TO KNOW
Distribution Evaluation
The requirements below are subject to the following:
(1) PG&E at its discretion may still require DTT on any DG system, especially for those that may not trip for end of line faults and has significant fault current contributions.
(2) Phase and ground protection are required to detect end-of-line faults. This may be waived for smaller certified units that have aggregated fault current contribution less than 10% and expected to trip due to anti-islanding protection after the feeder breaker tripped.
Utility Bulletin: TD-2306B-002 Publication Date: 11/15/2017 Rev: 6
Distributed Generation Protection Requirements
PG&E Public ©2017 Pacific Gas and Electric Company. All rights reserved. Page 2 of 12
(3) These exemptions do not apply to certified and non-certified Inverters with Stand-Alone capabilities.
(4) Transmission DTT requirements are independent and still apply.
(5) For a line section with all certified inverters, reclose blocking will not be required if the first reclose can be delayed to 10 seconds.
(6) If an existing uncertified DG already has DTT then this uncertified DG would not count towards the 10% limit for the “other machine or uncertified DG is > 10% of project” screen. Other uncertified DG with previously approved protection may still need to be re-studied on a case by case basis.
1 Certified Inverter:
1.1 < 40 kW, then
• DTT and ground fault protection are not required
1.2 ≥ 40 kW and < 1000 kW, and
1. Line section aggregated DG ≤ 50% of minimum load then
• DTT and ground fault protection are not required
2. Line section aggregated DG > 50% of minimum load, and
a. Aggregate machine ≤ 40% or uncertified DG is < 10% of the aggregate DG (all types) on line section, then
• DTT and ground fault protection are not required
b. Aggregate machine > 40% or uncertified DG is > 10% of the aggregate DG (all types) on line section requires:
• Ground Fault Protection and Reclose Blocking
• PG&E SCADA equipped recloser or interrupter
1.3 ≥ 1000 kW, and
Line section aggregated DG ≤ 50% of minimum load, then
• Requires PG&E SCADA equipped recloser or interrupter
1. Line section aggregated DG > 50% of minimum load, and
a. Aggregate machine ≤ 40% or uncertified DG is < 10% of the aggregate DG (all types) on line section, and
Utility Bulletin: TD-2306B-002 Publication Date: 11/15/2017 Rev: 6
Distributed Generation Protection Requirements
PG&E Public ©2017 Pacific Gas and Electric Company. All rights reserved. Page 3 of 12
(1) Short circuit contribution ratio ≤ 10%, then
• PG&E SCADA equipped recloser or interrupter
(2) Short circuit contribution ratio > 10%, then requires:
• Ground Fault Protection and Reclose Blocking
• PG&E SCADA equipped recloser or interrupter
b. Aggregate machine > 40% or uncertified DG is > 10% of the aggregate DG (all types) on line section requires:
• Ground Fault Protection and Reclose Blocking
• PG&E SCADA equipped recloser or interrupter
2 Uncertified Inverter:
Requires:
• Ground Fault Protection and Reclose Blocking
• PG&E SCADA equipped recloser or interrupter
• Customer side interrupter or recloser
• Redundant sets of PG&E approved protective relays
3 Machine – Induction or Synchronous:
3.1 < 40 kW, then DTT and ground fault protection are not required
3.2 ≥ 40 kW and < 400 kW, and
1. Line section aggregated DG ≤ 50% of minimum load, and
a. Short circuit contribution ratio ≤ 10%, then requires:
• Redundant sets of PG&E approved protective relays
b. Short circuit contribution ratio > 10%, then requires:
• Ground Fault Protection and Reclose Blocking
• Redundant sets of PG&E approved protective relays
2. Line section aggregated DG > 50% of minimum load, then requires:
Utility Bulletin: TD-2306B-002 Publication Date: 11/15/2017 Rev: 6
Distributed Generation Protection Requirements
PG&E Public ©2017 Pacific Gas and Electric Company. All rights reserved. Page 4 of 12
• Ground Fault Protection and Reclose Blocking
• PG&E SCADA equipped recloser or interrupter
• Redundant sets of PG&E approved protective relays
3.3 ≥ 400 kW, and
1. Line section aggregated DG ≤ 50% of minimum load, then requires:
• Ground Fault Protection and Reclose Blocking
• Redundant sets of PG&E approved protective relays
2. Line section aggregated DG > 50% of minimum load, then requires:
• Ground Fault Protection and Reclose Blocking
• PG&E SCADA equipped recloser or interrupter
• Redundant sets of PG&E approved protective relays
Note: When distribution upgrades such as reclose blocking are required additional time is needed before the DG facility is allowed to parallel with the PG&E system.
Flow chart – 1 is appended in reference to the requirements in sections 1-3 above.
Transmission and Substation Evaluation
For distributed generation,( i.e. generation connected to non-dedicated distribution circuits), the protection requirements for substation and transmission installations are as follows:
The requirements below are subject to the following:
(1) PG&E at its discretion may still require DTT on any DG system, especially for those that may not trip for end of line faults and has significant fault current contribution.
(2) If an existing uncertified DG already has DTT this uncertified DG would not count towards the 40% limit for machines or the 10% limit of “Other uncertified DG”. This includes existing hardwire CB tripping. Other uncertified DG with previously approved protection may still need to be restudied on a case per case basis.
(3) The machine generation shall be fixed P/Q type (fixed power factor).
(4) Excess generation on an ungrounded system could lead to temporary phase to ground overvoltages during transmission SLG faults, an evaluation will be needed to determine if overvoltage mitigation is required.
Utility Bulletin: TD-2306B-002 Publication Date: 11/15/2017 Rev: 6
Distributed Generation Protection Requirements
PG&E Public ©2017 Pacific Gas and Electric Company. All rights reserved. Page 5 of 12
(5) These exemptions do not apply to certified and non-certified Inverters with Stand-Alone capabilities.
4 Certified Inverter Substation and Transmission Line Section Review:
4.1 Substation Transformer
1. Transformer aggregated DG ≤ 50% of minimum load then
• DTT and transformer tripping is not required. End of review.
2. Transformer section aggregated DG > 50% of minimum load
If the substation transformer is ungrounded then
a. Evaluation will be required which may include grounding the transformer or installation of an overvoltage tripping scheme to prevent overvoltage of Transmission equipment on the affected line section.
If the substation transformer is grounded
b. Aggregate machine ≤ 40% or uncertified DG to total generation ratio is < 10% of the transformer aggregate DG (all types), then
• DTT and transformer tripping are not required continue to substation review.
c. Aggregate machine > 40% or uncertified DG to total generation ratio is > 10% of the transformer aggregate DG (all types), the following is required:
• Transformer protection tripping of feeder breakers is required. Tripping via the HV Bus Differential or Total Overcurrent (TOC) scheme would also be required for a single transformer station. Continue to substation review.
4.2 Substation Review
1. Total Substation aggregated DG ≤ 50% of minimum load, then
• DTT and transformer tripping are not required. End of review.
2. Total Substation aggregated DG > 50% of minimum load, and
a. Aggregate machine ≤ 40% or uncertified DG to total generation ratio is < 10% of the substation aggregate DG (all types), then
• DTT and transformer tripping are not required continue to transmission line review.
Utility Bulletin: TD-2306B-002 Publication Date: 11/15/2017 Rev: 6
Distributed Generation Protection Requirements
PG&E Public ©2017 Pacific Gas and Electric Company. All rights reserved. Page 6 of 12
b. Aggregate machine > 40% or uncertified DG to total generation ratio is > 10% of the substation aggregate DG (all types), the following is required:
• Station tripping via the HV Bus Differential or Total Overcurrent (TOC) scheme is required. Continue to transmission line review.
4.3 Transmission Line Section Review
1. Total line section aggregated DG ≤ 50% of minimum load, then
• DTT from transmission terminals to feeder breakers is not required. End of review.
2. Total Substation aggregated DG > 50% of minimum load, and
a. Aggregate machine ≤ 40% or uncertified DG to total generation ratio is < 10% of the line section aggregate DG (all types), then
• DTT from transmission terminals to feeder breakers is not required. End if review.
b. Aggregate machine > 40% or uncertified DG to total generation ratio is > 10% of the line section aggregate DG (all types), then the following is required:
• DTT from transmission terminals to feeder breakers is required.
• Reclose blocking at the transmission terminals is required if not installed.
A second flow chart is appended in reference to the requirements in section 4 above.
5 Machine Based Generation Substation and Transmission Line Section Review:
The requirements below are subject to the following:
(1) PG&E at its discretion may still require DTT on any DG system, especially for those that may not trip for end of line faults and has significant fault current contribution.
(2) If an existing uncertified DG already has DTT this uncertified DG would not count towards the 40% limit for machines or the 10% limit of “Other uncertified DG”. This includes existing hardwire CB tripping. Other uncertified DG with previously approved protection may still need to be restudied on a case per case basis. The machine generation shall be fixed P/Q type (fixed power factor).
(3) Excess generation on an ungrounded system could lead to temporary phase to gnd overvoltages during transmission SLG faults, an evaluation will be needed to determine the if overvoltage mitigation is required.
Utility Bulletin: TD-2306B-002 Publication Date: 11/15/2017 Rev: 6
Distributed Generation Protection Requirements
PG&E Public ©2017 Pacific Gas and Electric Company. All rights reserved. Page 7 of 12
(4) Phase and ground fault detection for transmission EOL faults is required via 59N, 51N, 51C, 51V or 21 elements. Small generators may not be able to detect all transmission EOL faults, therefore as long as aggregate gen is < 50% of minimum load, EOL fault detection for all transmission faults is not required. For generation with total SCCR > 0.1 EOL fault detection is required for all transmission faults.
5.1 Substation Transformer
1. Transformer aggregated DG ≤ 50% of minimum load then
a. DTT and transformer tripping is not required. End of review.
2. Transformer section aggregated DG > 50% of minimum load.
If the substation transformer is ungrounded then
a. Evaluation will be required which may include grounding the transformer or installation of an overvoltage tripping scheme to prevent overvoltage of Transmission equipment on the affected line section.
If the substation transformer is grounded
b. Aggregate machine generation to total generation ratio is < 40% or aggregate uncertified DG to total generation ratio is ≤ 10%, then
(1) Transformer Aggregate machine generation ≤ 50% of minimum load then
• DTT and transformer tripping are not required continue to substation review.
(2) Transformer Aggregate machine generation > 50% of minimum load then
• DTT and transformer tripping are required continue to substation review.
c. Aggregate machine generation to total generation ratio is > 40% or aggregate uncertified DG to total generation ratio is > 10%, the following is required:
(1) Transformer protection tripping of feeder breakers is required. Tripping via the HV Bus Differential or Total Overcurrent (TOC) scheme would also be required for a single transformer station. Continue to substation review.
Utility Bulletin: TD-2306B-002 Publication Date: 11/15/2017 Rev: 6
Distributed Generation Protection Requirements
PG&E Public ©2017 Pacific Gas and Electric Company. All rights reserved. Page 8 of 12
5.2 Substation Review
1. Total Substation aggregated DG ≤ 50% of station minimum load, then
a. DTT and transformer tripping are not required. End of review.
2. Total Substation aggregated DG > 50% of station minimum load, and
a. Aggregate machine generation to total generation ratio is < 40% or uncertified DG to total generation ratio is ≤ 10% of the substation aggregate DG, then
(1) Station Aggregate machine generation ≤ 50% of minimum load then.
• Station tripping via the HV Bus Differential or Total Overcurrent (TOC) scheme is not required.
(2) Station Aggregate machine generation >50% of minimum load then
• Station tripping via the HV Bus Differential or Total Overcurrent (TOC) scheme is required. Continue to transmission line review.
b. Aggregate machine generation to total generation ratio is > 40% or uncertified DG to total generation ratio is > 10% of the substation aggregate DG, the following is required:
(1) Station tripping via the HV Bus Differential or Total Overcurrent (TOC) scheme is required. Continue to transmission line review.
5.3 Transmission Line Section Review
1. Total line section aggregated DG ≤ 50% of minimum line section load, then
a. DTT from transmission terminals to feeder breakers is not required. End of review.
2. Total Substation aggregated DG > 50% of minimum line section load, and
a. Aggregate machine generation to total generation ratio is < 40% or uncertified DG to total generation ratio is ≤ 10% of the line section aggregate DG, then
(1) Line Section Aggregate machine generation ≤ 50% of minimum load then.
• DTT from transmission terminals to feeder breakers is not required.
Utility Bulletin: TD-2306B-002 Publication Date: 11/15/2017 Rev: 6
Distributed Generation Protection Requirements
PG&E Public ©2017 Pacific Gas and Electric Company. All rights reserved. Page 9 of 12
(2) Line Section Aggregate machine generation >50% of minimum load then
• DTT from transmission terminals to feeder breakers is t required.
b. Aggregate machine generation to total generation ratio is > 40% or uncertified DG to total generation ratio is > 10% of the line section aggregate DG, then the following is required:
(1) DTT from transmission terminals to feeder breakers is required.
(2) Reclose blocking at the transmission terminals is required if not installed
A third flow chart is appended in reference to the requirements in section 5 above.
DOCUMENT APPROVER
Roozbeh (Rudy) Movafagh, Manager, Distribution Standards & Strategy
DOCUMENT CONTACT
Brandon Tran, Supervisor, Electric Generation Interconnection, 415.973.2712 [email protected]
Chase Sun, Principal Engineer, DG, Distribution Planning & Reliability
Phuoc Tran, Distribution Generation Engineering Supervisor, Electric Operations
Mike Jensen, Supervising Protection Engineer, System Protection
Dan Jantz, Engineering Standards Technical Specialist, Expert, Distribution Standards
INCLUSION PLAN
This bulletin will reside on the DIH webpage without an inclusion plan at this time.
Utility Bulletin: TD-2306B-002 Publication Date: 11/15/2017 Rev: 6
Distributed Generation Protection Requirements
PG&E Public ©2017 Pacific Gas and Electric Company. All rights reserved. Page 10 of 12
Utility Bulletin: TD-2306B-002 Publication Date: 11/15/2017 Rev: 6
Distributed Generation Protection Requirements
PG&E Public ©2017 Pacific Gas and Electric Company. All rights reserved. Page 11 of 12
Utility Bulletin: TD-2306B-002 Publication Date: 11/15/2017 Rev: 6
Distributed Generation Protection Requirements
PG&E Public ©2017 Pacific Gas and Electric Company. All rights reserved. Page 12 of 12
Sta
rt M
achi
ne G
ener
atio
n R
evie
wN
ote-
4
Agg
rega
te
Gen
erat
ion
> 5
0%
Tran
sfor
mer
Min
24
hr A
ggre
gate
Lo
ad
No
Yes
Agg
rega
te M
achi
ne
Gen
to T
otal
Gen
R
atio
>40
% o
r A
ggre
gate
Unc
ertif
ied
DG
(ie
Win
d) to
Tot
al
Gen
Rat
io >
10 %
N
ote-
2
Box
BY
es
No
Bac
kfee
d in
to
Tran
smis
sion
Lin
e S
ectio
n >
50%
Min
24
hr L
ine
Sec
tion
Agg
rega
te L
oad
Agg
rega
te M
achi
ne
Gen
to T
otal
Gen
R
atio
>40
% o
r A
ggre
gate
Unc
ertif
ied
DG
( ie
Win
d ) to
Tot
al
Gen
Rat
io >
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N
ote -
2B
ox D
Box
AN
o D
TT o
r XFM
R tr
ippi
ng is
re
quire
d. P
roce
ed to
nex
t ev
alua
tion
poin
t if r
equi
red.
Box
BX
FMR
pro
tect
ion
tripp
ing
of
feed
er b
reak
ers
is re
quire
d.S
tatio
n tri
ppin
g vi
a th
e H
V
Bus
Diff
eren
tial o
r TO
C
sche
me
may
als
o be
re
quire
d.
Box
DD
TT fr
om tr
ansm
issi
on
term
inal
s to
feed
er b
reak
ers
is re
quire
d . R
eclo
se
bloc
king
at t
he tr
ansm
issi
on
term
inal
s is
requ
ired
if no
t in
stal
led.
Not
e -2
If an
exi
stin
g M
achi
ne/
Unc
ertif
ied
DG
alre
ady
has
DTT
this
unc
ertif
ied
DG
w
ould
not
cou
nt to
war
ds th
e ra
tio li
mit
of “O
ther
U
ncer
tifie
d D
G” .
Thi
s in
clud
es e
xist
ing
hard
wire
C
B tr
ippi
ng. O
ther
un
certi
fied
DG
with
pr
evio
usly
app
rove
d pr
otec
tion
may
stil
l nee
d to
be
rest
udie
d on
a c
ase
per
case
bas
is.
•Th
e m
achi
ne
gene
ratio
n sh
all b
e fix
ed P
/Q ty
pe (f
ixed
po
wer
fact
or).
Sub
stat
ion
Tran
sfor
mer
H
V W
ye G
ND
Not
e-3
Box
CN
o
Yes
Not
e-3
Exc
ess
gene
ratio
n on
an
ungr
ound
ed s
yste
m c
ould
le
ad to
tem
pora
ry p
hase
to
gnd
over
volta
ge' s
dur
ing
trans
mis
sion
SLG
faul
ts.
Miti
gatio
n m
ay b
e re
quire
d
Yes
No
Yes
Not
e-4
Pha
se a
nd g
roun
d fa
ult d
etec
tion
for
trans
mis
sion
EO
L fa
ults
is re
quire
d vi
a 59
N, 5
1N, 5
1C, 5
1V o
r 21
elem
ents
. S
mal
l gen
erat
ors
may
no
t be
able
to d
etec
t all
trans
mis
sion
EO
L fa
ults
, the
refo
re
as lo
ng a
s ag
greg
ate
gen
is <
50 %
of
min
imum
load
, EO
L fa
ult
dete
ctio
n fo
r all
trans
mis
sion
faul
ts
is n
ot re
quire
d. F
or g
ener
atio
n w
ith
tota
l SC
CR
> 0
.1 E
OL
faul
t de
tect
ion
is re
quire
d fo
r all
trans
mis
sion
faul
ts
Box
CE
valu
atio
n w
ill b
e re
quire
d w
hich
may
incl
ude
grou
ndin
g th
e tra
nsfo
rmer
or
inst
alla
tion
of a
n ov
ervo
ltage
tri
ppin
g sc
hem
e to
pre
vent
ov
ervo
ltage
of T
rans
mis
sion
eq
uipm
ent o
n th
e af
fect
ed
line
sect
ion.
Tran
smis
sion
R
evie
w
Box
A
Box
A
To S
ubst
atio
n R
evie
w
Sub
stat
ion
Rev
iew
Agg
rega
te
Gen
erat
ion
> 5
0%
Sta
tion
Min
24h
r A
ggre
gate
Loa
d
No
Yes
Agg
rega
te M
achi
ne
Gen
to T
otal
Gen
R
atio
>40
% o
r A
ggre
gate
Unc
ertif
ied
DG
(ie
Win
d) to
Tot
al
Gen
Rat
io >
10 %
N
ote-
2B
ox B
Yes
No
Box
A
To T
rans
mis
sion
R
evie
w
No
Box
A
Box
A
Mac
hine
Bas
ed G
ener
atio
n D
TT R
equi
rem
ents
for >
40k
W
Tran
smis
sion
Bac
kfee
dA
ggre
gate
Syn
ch
Gen
erat
ion
> 5
0%
Tran
sfor
mer
Min
24
hr L
oad
No
Yes
Agg
rega
te M
achi
ne
Gen
erat
ion
> 5
0%
Min
24h
r Loa
d
YesNo
Agg
rega
te M
achi
ne
Gen
erat
ion
> 5
0%
Min
24h
r Loa
d
Box
AN
o
Yes