Transcript LADWP RAS 2016-11-14

• An operational study was performed to analyze the 230
kV transmission system south of Haskell Canyon to the
LA Basin revealed thermal overload issues
• The transmission circuits involved in the study include
–
–
–
–
Haskell-Rinaldi Line 1
Haskell-Sylmar Line 1
Haskell-Olive Line 1
Olive-Northridge Line 1
3
4
• The transmission network south of Haskell
Canyon Switching Station is vulnerable when
one or more circuits is out.
• With circuits out, the operational studies show
that we can exceed the 2-hour rating for other
circuits.
• It was determined that the OVRAS could be used
with manual arming to address this precontingency
5
6
• HSK-OLV 1 Out and Line Loss on HSK-RIN 1
– Pre-contingency of HSK-OLV Line 1 out.
– Load Dispatcher will manually arm Contingency A.
– During this pre-contingency, the system is configured to
radially connect CAS-PP to SYL-SS and to radially connect
BAR-SS to Rinaldi RS.
– The RAS logic will then detect loss of HSK-RIN Line 1 and
initiate the remedial action for Contingency A.
– Remedial Action for Contingency A is to trip Inyo E1 and E2
CBs and to trip Barren Ridge E32 and E33 CBs.
7
8
• HSK-SYL1 Out and Line Loss on HSK-RIN 1
– Pre-contingency of HSK-SYL Line 1 out.
– Load Dispatcher will manually arm Contingency B.
– During this pre-contingency, the system is configured to
radially connect CAS-PP to OLV-SS and to radially connect
BAR-SS to Rinaldi RS.
– The RAS logic will then detect loss of HSK-RIN Line 1 and
initiate the remedial action for Contingency B.
– Remedial Action for Contingency B is to trip Inyo E1 and E2
CBs and to trip Barren Ridge E32 and E33 CBs.
9
10
• OLV-NOR 1 Out and Line Loss on HSK-RIN 1
– Pre-contingency of OLV-NOR Line 1 out.
– Load Dispatcher will manually arm Contingency C.
– During this pre-contingency, the system is configured to
radially connect CAS-PP to SYL-SS and to radially connect
BAR-SS to Rinaldi RS.
– The RAS logic will then detect loss of HSK-RIN Line 1 and
initiate the remedial action for Contingency C
– Remedial Action for Contingency C is to trip Inyo E1 and E2
CBs and to trip Barren Ridge E32 and E33 CBs
11
12
• HSK-RIN 1 Out and Line Loss on HSK-SYL 1
– Pre-contingency of HSK-RIN Line 1 out.
– Load Dispatcher will manually arm Contingency D.
– During this pre-contingency, the system is configured to
radially connect CAS-PP to OLV-SS and to radially connect
BAR-SS to Sylmar SS.
– The RAS logic will then detect loss of HSK-SYL Line 1 and
initiate the remedial action for Contingency D.
– Remedial Action for Contingency D is to trip Inyo E1 and E2
CBs and to trip Barren Ridge E32 and E33 CBs
13
• BAR-SS radially connected to SYL-SS
14
• Contingencies A, B, C, and D connect the Barren
Ridge Substation connection to the LA Basin through
a single radial circuit
– Contingencies A, B, and C
• HSK-RIN L1
– Contingency D
• HSK-SYL L1
• When there is an A, B, C, or D contingency trip, the
OVRAS III isolates LADWP from SCE.
15
HASKELL CANYON SS
Contingencies
INYO-BAR L1
BARREN RIDGE SS
BEACON SS
INYO SS
E41 E43 E51 E53 E71 E72 E73 E82 E83 E92 E93 E12 E13 E31 E32 E33 E41 E42 E43 E51 E52 E53 E51 E52 E71 E72 E1 E2
X2 X2
BAR-HSK L1
BAR-HSK L2
X X X1 X
BAR-HSK L3
BAR-HSK L2
BAR-HSK L3
HSK-RIN L1
HSK-OLV L1 X1 X1 X1 X1 X1
X1
X X X X
HSK-SYL L1
A1 & HSK-RIN
X
1 Line Loss
B1 & HSK-RIN
X
1 Line Loss
C1 & HSK-RIN
X
1 Line Loss
D1 & HSK-SYL
X
1 Line Loss
Note 1: X1 Trips CBs for an open ended condition North to South
Note 2: X2 Trips Barren Ridge CBS E32 & E33 when Inyo CB-E1 comes OPEN
Note 3: X3 If Inyo E1 or E2 fails to open SCE 612 CB Trips after a 10cy delay
SCE
612
X1
X
X3
X
X
X3
X
X
X3
X
X
X
X3
X
X
X
X3
X
X
X
X3
X
X
X
X3
X X1 X
X1
X
X
X
X X1 X
X1 X1 X1 X1 X
X
X
X
X
X
X
16
• Add “CB Assume Open” Logic
– Problem: If one CB opens on a transmission line and a second CB
is closed with disconnects open, the RAS could fail to detect a
line loss condition.
• If one CB is out on maintenance (line hot with disconnects
open), it is possible to close the CB for maintenance
purposes (testing, timing, etc)
– Requirement: At either end of the circuit, both CBs must be
open, and the current must be < the charging current of the line.
– If the RAS receives a “CB Assume Open” signal, the RAS logic will
maintain an open status for the affected CB, and will ignore any
pallet trouble coming from the CB
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18
• The operator must do the following:
1. Press the Local Button for five (5) seconds to put the
Relay under a local command.
19
2. After the Relay is under a local command, press the
pushbutton for the desired “CB Assume Open.”
3. After pressing the CB Assume Open, an alarm “CB
Assumed Open” is sent to ECC along with the station
name and bay number.
20
• Four more contingencies were added, with manual
arming
• No additional equipment was necessary
• New settings logic was implemented for the new
contingencies
• CB assume open was added to increase security on
line loss detection
21
• Removing Unit 3
– After units 4, 5, 6, and 7 were declared OK for
service, Unit 3 was declared out of service
– Scattergood will have two (2) 230kV cables
• Existing Scattergood-Olympic Line 2
(SCA-OLY 2)
• New Scattergood-Olympic Cable A
(SCA-OLY A) which is currently under
construction (Future 2017?)
24
25
• The purpose of the Scattergood RAS is to do the
following:
– Accommodate four (4) new generators that
are replacing Unit 3 (Unit 3 Re-power)
– Accommodate an additional transmission
circuit 230kV Scattergood-Olympic Cable A
(SCA-OLY A)
– Replace outdated, existing RAS hardware
26
• Existing and New Generation (Installed 2015)
Unit
Type
Net Capacity in MW
1
Conventional Boiler
180
2
Conventional Boiler
183
3
Super-critical Boiler
445
4&5
Combined Cycle
Unit 4 is the combustion turbine
Unit 5 is the hear recovery unit
216
6
Combustion Turbine
101
7
Combustion Turbine
101
27
• Existing and New Transmission
Unit
Voltage
Class, kV
Continuous 2-Hour MVA
MVA Rating
Rating
Scattergood-Airport 1
138
234
278
Scattergood-Airport 2
138
234
278
Scattergood-Olympic Line 2
230
349
349
Scattergood-Olympic Cable A
(est. 2017)
230
656
796
230/138
500
500
RS-L Bank E (Auto/PST)
28
Before
After
Unit 1: 183 MW
Unit 1: 121 MW
Unit 2: 183 MW
Unit 2: 183 MW
Unit 3: 450 MW
Unit 4: 216 MW
Unit 5: 118 MW
Unit 6: 89 MW
Unit 7: 89 MW
29
• SCA-RAS Remedial Logic after Removing Unit 3
– GE-N60 relays for Unit 3 Systems A and B were declared
out of service and removed
– No more inputs from the Unit 3 RAS to the RAS
Controller
– Remote GE N60 devices have been removed from the
controller remote device listing
– No change to Arming. Arming is determined by the MW
flows on Scattergood transmission circuits not by Unit 3
output
30
• A limitation was discovered in firmware version 1.82
related to the ability of the firmware to handle large
program files.
• The solution was to use a “heartbeat” within the GE
C90P to maintain operation to ensure overall system
health and to ensure the program is operating correctly.
• The LADWP worked with GE and a firmware revision has
been released to correct the limitation. The firmware will
be updated during the next maintenance cycle.
31
• We will implement the same “CB Assume Open”
logic that was developed for OVRAS.
32
• Scattergood Unit 3 was the last unit programmed to
trip, therefore removal did not affect other logic.
• The GE-C90P firmware upgrades and the CB Assume
Open Logic will be implemented during the next
maintenance cycle.
33
• Prevent overloads on the oil-filled 138kV HarborWilmington Cables D and E
• The RAS trips pre-selected units at HAR-GS to
prevent post-contingency loading on the
remaining Harbor-Wilmington Cable D or E from
exceeding its own circuit emergency ratings
36
• Original Harbor Area Transmission Configuration
•
•
Loss of either Cable D or E stresses the
remaining cable.
Trips appropriate units at Harbor GS to
relieve post-contingency loading.
• Loss of either Cable D or E
stresses the remaining cable.
• Trips appropriate units at Harbor
GS to relieve post-contingency
loading.
37
•  HAR-GS generation = 458 Net MW
•  HAR-GSold Transmission = 575 MVA
emergency
•  HAR-GSnew Transmission = 912 MVA
emergency
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39
• A major re-location and re-conductoring of the
LDWP Harbor 138kV transmission system has been
completed (RS-C Bypass).
• The Harbor RAS is no longer required.
• Therefore, LADWP is requesting approval to remove
the Harbor LAPS from the WECC RASRS database.
40
• In response to NERC CIP-014-2 standard, performed initial risk
assessment and determined that the Toluca Substation was
deemed a critical station.
• Implementing the Hollywood RAS to shed sufficient loads at
the Hollywood Substation to prevent transient instability,
thermal overload, and voltage instability problems associated
with the loss of the Toluca Substation (RS-E) or simultaneous
losses of the Toluca-Hollywood triple lines.
• The CIP-014-2 mitigation includes installing primary and
redundant RAS systems at the Toluca, Hollywood, and Fairfax
substations.
44
• The Hollywood RAS will be designed and built to the
Wide Area Protection RAS standard for WECC.
• This includes all redundancy requirements for
equipment and infrastructure.
45
46
47
• CIP-014-2 R1 requires transmission owners to
perform a risk assessment of transmission stations
and substations that meet applicability criteria set
forth in CIP-014-2.
• Initial study results, using the approved WECC 2020
Heavy Summer base case, showed that complete loss
of the Toluca 230 kV substation could cause thermal
overload, voltage violations, and system instability in
the LA Basin.
• Toluca was deemed to be a critical facility.
49
• The purpose of this study is to evaluate whether a
Remedial Action Scheme (RAS) at Hollywood that
will monitor the flow of the Toluca-Hollywood lines
and shed sufficient load at Hollywood Station would
prevent voltage collapse, thermal overload and/or
widespread instability in the system in the following
two contingencies:
• Loss of Toluca (RS-E) (NERC CIP-014-2 Standard)
• Simultaneous losses of Toluca-Hollywood Triple lines
50
• Outage results will be measured by the following criteria:
– Thermal overloads beyond facility emergency ratings after
taking the overloaded facility out of service and attempting
a new solution for no more than three iterations;
– Voltage deviation exceeding ± 10%;
– Cascading outage/voltage collapse; or
– Frequency below under-frequency load shed points.
51
• The risk assessment will take into account the impact of the loss of
generation connected to applicable Transmission stations or Transmission
substations. Based on engineering judgment, the risk assessment may
include one or more of the following categories of outages for those
facilities that have not been identified during the steady state analysis:
– Three-phase fault located on highest voltage bus of station as identified the
most critical bus;
– Any Special Protection System (or Remedial Action Scheme) located at the
station fails to function; or
– Operation, partial operation, or mis-operation of a fully redundant Special
Protection System (or Remedial Action Scheme) in response to an event or
abnormal system condition for which it was not intended to operate.
52
• The loss of an entire Transmission station or substation including all
voltage levels represents an extreme event, and is more severe than local
area events defined in the Table 1 – Steady State & Stability Performance
Extreme Events section of the NERC TPL-001-4 Transmission Planning
Standard for which the most severe similar event is “loss of a switching
station or substation to one voltage level plus transformers”. The TPL-0014 standard provides no performance criteria for Extreme Events, and only
“if the analysis concludes there is Cascading caused by the occurrence of
extreme events, an evaluation of possible actions designed to reduce the
likelihood or mitigate the consequences and adverse impacts of the
event(s) shall be conducted”. Therefore specific performance criteria for
use with this assessment are provided in the steady state and dynamic
stability methodology
53
• Since there are no specific performance requirements for extreme events,
the assumption will be made that post-contingency events play out over a
period of time that allows automatic tap changers and reactive devices to
operate, as well as limited operator actions via SCADA or EMS to switch
capacitors and/or reactors, disconnect overloaded transmission lines and
transformers, trip or adjust generation, and to shed load. Phase shifting
transformers and DC lines will not be adjusted. A governor power flow
solution will be utilized, and generators will be set to regulate their terminal
voltage to the pre-contingency voltage level. It is further assumed that the
event is significant enough that tie-line control will be disabled either
automatically or manually. If there is a Remedial Action Scheme (RAS) at
that substation, it will be considered disabled and RAS’s at other stations
will be considered active and will be implemented in the simulation.
54
•
•
•
•
Cascade analysis is limited to three successive solutions unless provided otherwise by
Transmission Owner. Operations of RAS that are not associated with the Transmission station
or substation being evaluated are permitted. After successive iterations, facilities that meet the
following criteria are removed from service and the case is re-solved.
Facilities loaded to 125% or greater of the established seasonal short term emergency rating;
this assumes the Transmission Operator is taking manual steps to restore the system which
may include tripping overloaded facilities, tripping or adjusting generation, and shedding load
when necessary to preserve the system.
Generators with terminal voltages below 0.90 per unit; since the voltage is below the normal
rating for generators, tripping may be due to loss of auxiliary loads or plant operator action to
protect the machine.
The process is repeated up to two additional times beyond the initial solution until either the
case fails to converge, which indicates the potential for system collapse, or until no violations
of the above two criteria are found, which indicates that the system has reached a stable
operating point
55
• Transient stability analysis will be conducted to
determine whether or not widespread instability
occurs and will be performed on the selected base
case. The study will simulate loss of an entire
transmission station or substation including all
voltage levels.
56
57
• The Hollywood RAS monitors three (3) substations
– Toluca Substation
– Hollywood Substation
– Fairfax Substation
58
59
• TOL-HOL L1, L2, & L3 Line Loss, HOL-FAR A & B IN,
HOL Banks > 325 MW
– Toluca-Hollywood triple line loss
– Pre-contingency of Hollywood-Fairfax cables A and B IN
– Hollywood Load Banks > 325 MW
– The RAS logic with then detect the three preceding
conditions and initiate the remedial action for Contingency 1
– Remedial Action for Contingency 1 is to trip the Hollywood
Load Bank(s) when the total load exceeds 325 MW
60
• TOL-HOL L1, L2, & L3 Line Loss, HOL-FAR A Line Loss
& B IN, HOL BANKS > 167 MW
– Toluca-Hollywood triple line loss
– Pre-contingency of Holly-Fairfax A Line Loss and B IN
– Hollywood Load Banks > 167 MW
– The RAS logic will then detect the three preceding
conditions and initiate the remedial action for Contingency 2
– Remedial Action for Contingency 2 is to trip the Hollywood
Load Bank(s) when the total load exceeds 167 MW
61
• TOL-HOL L1, L2, & L3 Line Loss, HOL-FAR B Line Loss &
B IN, HOL BANKS > 167 MW
– Toluca-Hollywood triple line loss
– Pre-contingency of Holly-Fairfax B Line Loss and A IN
– Hollywood Load Banks > 167 MW
– The RAS logic will then detect the three preceding
conditions and initiate the remedial action for Contingency 3
– Remedial Action for Contingency 3 is to trip the Hollywood
Load Bank(s) when the total load exceeds 167 MW
62
• TOL-HOL L1, L2, & L3 Line Loss, HOL-FAR A or B Line
Loss, HOL BANKS > 167 MW
– Toluca-Hollywood triple line loss
– Pre-contingency of Holly-Fairfax A or B Line Loss
– Hollywood Load Banks > 167 MW
– The RAS logic will then detect the three preceding
conditions and initiate the remedial action for Contingency 4
– Remedial Action for Contingency 4 is to trip the Hollywood
Load Bank(s) when the total load exceeds 167 MW
63
• Contingency 1 operates as follows:
Contingency 1
Arming Conditions
Remedial Actions
Auto-Arming Conditions
Method
TOL-HOL L1, L2, or L3 IN
Line loss detection
HOL-FAR A IN - Precontingency
Line loss detection -pre-contingency for load
shedding threshold
HOL-FAR B IN - Precontingency
Line loss detection –
pre-contingency for load
shedding threshold
Banks A, B, C, and D > 325 MW
Load threshold detection
Banks A, B, C, and D
Minimum load shedding to 325
MW total for all banks
64
• Contingency 2 operates as follows:
Contingency 2
Arming Conditions
Remedial Actions
Auto-Arming Conditions
Method
TOL-HOL L1, L2, or L3 IN
Line loss detection
HOL-FAR A Line Loss -Precontingency
Line loss detection -pre-contingency for load
shedding threshold
HOL-FAR B IN –
Precontingency
Line loss detection –
pre-contingency for load
shedding threshold
Banks A, B, C, and D > 325 MW
Load threshold detection
Banks A, B, C, and/or D
Minimum load shedding to 167
MW total for all banks
combined.
65
• Contingency 3 operates as follows:
Contingency 3
Arming Conditions
Remedial Actions
Auto-Arming Conditions
Method
TOL-HOL L1, L2, or L3 IN
Line loss detection
HOL-FAR A IN -- Precontingency
Line loss detection -pre-contingency for load
shedding threshold
HOL-FAR B Line Loss –
Precontingency
Line loss detection –
pre-contingency for load
shedding threshold
Banks A, B, C, and D > 325 MW
Load threshold detection
Banks A, B, C, and/or D
Minimum load shedding to 167
MW total for all banks
combined.
66
• Contingency 4 operates as follows:
Contingency 4
Arming Conditions
Remedial Actions
Auto-Arming Conditions
Method
TOL-HOL L1, L2, or L3 Line Loss
Line loss detection
HOL-FAR A or B Line Loss –
Precontingency
Line loss detection -pre-contingency for load
shedding threshold
Banks A, B, C, and D > 167 MW
Load threshold detection
Banks A, B, C, and/or D
Minimum load shedding to 167
MW total for all banks
combined.
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68
TOL-HOL 1
TOLUCA
HOLLYWOOD
FAIRFAX
CBE201
CBE202
TOL-HOL 2
CBE101
CBE102
TOL-HOL 3
CBE191
CBE192
TOL-HOL 1
TOL-HOL 2
TOL-HOL 3
CBE21
CBE41
CBE12
CBE22
CBE42
HOL-FAR A
HOL-FAR B
E81
E72
HOL-FAR A
HOL-FAR B
E11
E21
CBE13
E12
E22
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• The Hollywood RAS will use the same logic as
previously used on other LADWP RAS installations
such as the Owens Valley RAS for Line Loss
Detection.
• The selection of what load to drop will consider which
Transformer Bank or Banks are necessary to shed
based upon the criteria and status of the HollywoodFairfax Cable A and B.
71
• The same models and types of devices will be utilized for HWDRAS:
– GE-N60 relays are used to
• Gather local data
• Transfer data using IEC-61850 telecommunications protocol
• Perform local trips
– GE-C90P relays
• Process all the data and run it through logic
• Use the IEC-61860 to send a remedial trip to the N60s
notifying them to trip their local breakers
• HWDRAS logic will be based on line loss detection as was done in
OVRAS
72
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Logic for Manual CB Assume Open to
Facilitate Work on CB Isolated from
System Via Open Disconnects
74
• The operator will have to do the following:
1. Press the Local button for five (5) seconds to place
the Relay under local command.
75
2. After the Relay is under Local command, press the
pushbutton for the desired “CB Assume Open.
3. An alarm “CB Assume Open” is sent to ECC with the
station name and bay number.
76
• After applying the RAS for the contingencies
– There is no system instability
– There are no thermal overloads or voltage
violations
– There are no violations of WECC transient voltage
criteria found in any studied contingencies
77
• The Hollywood RAS relays meet all CIP standards
met by the Owens Valley RAS as follows:
– CIP-007-6. R3.1 Malicious Code Prevention
– CIP-007-6. R4.1 Security Event Login
– CIP-007-6. R4.2 Security Event Monitoring
– CIP-008-5. R2.3 Cyber Security Incident
Response Plan Implementation and Testing
79
• Overall end-to-end test will be performed for commissioning
• This is a complete, comprehensive test using power system
simulators connected via satellite time sync
• To avoid a complete system outage, outputs will be checked
one terminal at a time
– Block RAS system with blocking switches
– Use multiple test sets and dummy breakers to simulate a
line loss
– Synchronize test sets with a GPS signal
– Trip test CBs one at a time
81
• The following will be checked and verified during the
commissioning test.
• RAS Settings
• Contingency Logic
• I/O
• CTs, PTs, 52a and 52b
Circuit Breaker Pallets
• Contingency Operation
• Contingency Time
Operation
• DC Circuitry Trips
• Communication Channels
• Wiring Prints
• Annunciator Alarms
• SCADA Controls and Status
Indications
82
• System Approach – Maintenance can be performed
from Barren Ridge for the entire RAS A or RAS B
system
• The Master Settings file will be used as a reference
to verify relay settings and logic
• If any unauthorized change is made to a Hollywood
RAS device, the system automatically sends an
alarm to the Grid Operations Center
83
1. Use the Viewpoint UR Engineer software to do the
following:
a)
Compare the relay settings and logic with the Master Settings file for
the device.
b) Verify that the settings and logic have not changed.
2. Perform a remote load check for each terminal to verify the
integrity of the PTs and CTs.
a)
Compare RAS A values with RAS B values
NOTE: Communication channels, CB pallets, C90P/N60 devices, and
contingencies arming are continuously monitored. If a failure event occurs,
the system automatically sends an alarm to the Grid Operations Center.
84
• This is an individual circuit approach, and work will be
performed on every circuit in the RAS A and B systems, one
system at a time.
• The Functional Test combined with the Annual Maintenance
checks the following to ensure compliance with PRC-005
• Settings and Logic
• Communication Channels
• Inputs and Outputs
• Arming Contingencies
• Communication Time Delay
• System Operating
Time Delay
• Automatic Arming
• CT and PT Integrity
• CIP Alarms
• 52-A and 52-B CB Pallets
• Trip Circuitry
• SCADA Controls
85
• Line loss detection initiates the Hollywood RAS
• Use of IEC-61850 telecommunication protocol
enables future growth and expansion through a
simple software modification
• HWDRAS fully complies with CIP Compliance
regulations
• Use of IEC-61850 makes maintenance much easier
87