mod-33 principle, criteria and methodology: pacific northwest’s principle_pacific northwest... ·...
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MOD-33 Principle, Criteria and Methodology: Pacific Northwest’s
Experience
Bo GongColumbiaGrid
WECC MVWG WorkshopNov. 2018, Salt Lake City
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This work is jointly contributed by 11 utilities in PNW:
Avista: Tracy Rolstad, Richard Maguire
BPA: Dmitry Kosterev, Dave Carthcart, Kalin Lee, Hamodi Hindi
Chelan County PUD: Zachary Zornes
Cowlitz County PUD: Jerod Vandehey
Douglas County PUD: Jeff Heminger, Leslie Corson
Grant County PUD: Ken Che, May Le
PacifiCorp: Song Wang
Puget Sound Energy: Shengli Huang, Sarah Davis
Seattle City Light: Desmond Chan, Dejene Mersha
Snohomish County PUD: Long Duong
Tacoma Power: Khanh Thai, Mark Pigman
Acknowledgement
2
NERC compliance became effective in 7/1/2017
Each Planning Coordinator performs power flow and dynamic validation every 24 months Comparing planning models with real time measurements
Steady-state measurements in western interconnection mostly comes from node-breaker WSM case
Real time dynamic measurements comes from PMU/DFR/EMS/SCADA
A guideline for unacceptable comparison discrepancy
A guideline to resolve unacceptable discrepancy
NERC MOD-33 Standard
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Tightly coupled transmission system in ColumbiaGrid footprint
9 PCs (Federal, Municipal, IOU)
Backbone 500kV and 230kV owned and operated by BPA, other utilities coupled to each other through 230kV and 115kV
Many small municipals GO and LSE
Hardly can shield the influence from neighbors’ models when utility evaluates their own performance
Joint efforts on system model validation led by ColumbiaGrid
8 CG members and 2 participants
PAC joined in August, 2018
System Model Validation in Pacific NW
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Extensive experience and better calibrated models serves as foundations to system wide model validation in PNW
Dynamic stability issues due to geographic factors Distribution of hydro generation
Concentrated load centers in coastal metropolitan area (Seattle and Portland)
High power transfer in long transmission lines
Power exchange with neighboring regions (California, British Columbia, and Montana) varied largely in direction and amount
Extensive model validation experience in the past 2 decades
The failure of reproducing Aug 10, 1996 WSCC outage by simulation
Improving load and generator models through MVWG
An online tool using PMU data developed by BPA to constantly improves dynamic models whenever a disturbance happened
High resolution measurement of PMU, DFR (BPA, PacifiCorp and PSE) to monitor major generation hubs, interties and load centers
SCADA and EMS measurements covers every corners of the footprint.
System Model Validation in Pacific NW
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In 2016, ColumbiaGrid and member utilities started to develop a process document satisfying NERC MOD-033 R1
Establish a documented process includes:
system condition/event selection
data acquisition
base case development
data review and correction
methodology, etc.
Include a guideline for determining “acceptable/unacceptable” power flow and dynamic comparison
Updating the guideline for “resolving unacceptable discrepancy”
https://www.columbiagrid.org/download.cfm?DVID=4747
CG MOD-33 Process Document
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CG’s MOD-33 Principles
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It is a system wide validation effort
Other NERC compliance (MOD-25/26/27) exists for plant level validation
A system wide efforts cover a large area, validate system performance for the whole region
1. Do not isolate good and bad models’ performance
Let them interact and contribute together to the system performance.
2. Do not tune a part of system to get other parts comparison good.
Comparing measurements all at the same time
3. As a bonus, you will see devices interact with each other during a complicated events
Normally not captured by staged tests or individual plant validation.
CG’s MOD-33 Principles
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Objective to improve system modeling
First we admit there are bad model/data
Located “bad” models/data is a very challenging task
“Unacceptable” criterion is a tool to help us distinguish good & bad
Do not set the bar too low so that everything become “good”
Accommodate discrepancies not coming from modeling aspects (measurement, software, etc)
Before chasing “bad”, started with a good case so that we are truly comparing “apple to apple”
A “bad” comparison should be truly caused by “bad” models, not other factors
90% of time spent in our study is to create a good case
It is an iterative process and we expect more and more stringent criterion when we make models better and better.
CG’s MOD-33 Principles
9
Ensure equal benefit to all participants
There are members and non-members whose transmission systems are tightly coupled.
Some utilities who own mostly 230kV~500kV transmission lines, some only have 115kV and below.
Some utilities owns a large amount of generation (hydro, gas, renewable, etc.), some are primarily a LSE.
A uniformed model validation process helps to bring all utilities modeling practice to a consistent standard, proving long term benefit
We validate all transmission system 115kV and above, treat equally transmission, load and generation.
CG’s MOD-33 Principles
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CG’s MOD-33 Criterion
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Power Flow Validation Criterion
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Parameters for
Comparison
Bandwidth for Comparison
115kV 230kV 300kV 345kV 500kV
Real Power flows
• Lines and transformers +/-10% (AC) +/-10% (AC) +/-10% (AC) +/-10% (AC) +/-10% (AC)
• Generators or 10 MW, or 20 MW, or 30 MW, or 50 MW, or 100 MW,
• HVDC, series cap, etc whichever is
larger
whichever is
larger
whichever is
larger
whichever is
larger
whichever is
larger
Voltages
• Transmission buses,
generator terminal, DC
lines’ terminals, reactive
device
+/-4% +/-3% +/-3% +/-3% +/-2%
Reference to several existing MOD 33 criterions and our own system validation studies
All 115 kV and above, different voltage use different acceptable band
MW Line flow: Max (a fix band, percentage actual flow)
Voltage: Percentage of actual measured voltage
Examples: A 230 kV line was measured at 600 MW flow, if the planning case flow is 535 MW, it
is exceed both 10% of the 600MW and 20 MW fixed band, it is “unacceptable”
A 115 kV line was measured at 150 MW flow, if the planning case flow is 135 MW, it is within 10% of the 150MW even though it exceed the 10MW fixed band, it is still “acceptable”
A 115kV line was measured at 50 MW flow, if the planning case flow is 58 MW. Even though it exceed the 10% of the 50 MW flow, it is still within 10MW fixed band, so it is still “acceptable”
A 115/500kV transformer was measured at 500 MW flow, if the planning case flow is 445 MW, it exceed both 115kV criterion (the 10% of 500 MW and 10MW fixed band for 115kV), regardless of the 500kV criterion, it is “unacceptable”
An HVDC line was measured at 1500 MW flow, the planning case has the flow at 1620MW. It exceed the 100MW fixed band (there is no 10% band for DC line), so it is “unacceptable”.
A 230 kV bus voltage was measured at 1.0 p.u., the planning case voltage is 1.025pu. It is within the 3% band, so it is “acceptable”.
Power Flow Validation Criterion
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Power Flow Validation Criterion
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Why we don’t use reactive power flow but real power flow
Real power flow can be done much efficiently as line loss is small, get source (generator), sink (load) and path (line status) correct, you will get it matched
Reactive power flow, each transmission line can individually generate or absorb reactive power, and it doesn’t travel far, not practical in a large area.
Why we don’t use reactive line flow but voltage
After having voltage matched everywhere in large area, system condition matches well in many other comparison (dynamics, real power, etc. )
Solving power flow, match voltage set points help you align voltage efficiently
Voltage difference are much easier to trace in transmission system than MVar flow
ColumbiaGrid will primarily adopt visual inspection to compare the real-time measurements and simulation.
As we use power flow validated case for dynamic validation, power flow criteria play an important role in validation results.
Dynamic Validation Criterion
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Dynamic comparison is different from steady state ones A band all along the trajectory, at final time, or after oscillation damped out?
Can we allow exception at the time of switching? If yes, then what action is eligible as a switching?
Percentage vs Absolute metrics? Percentage value are depends on the base value, what if the base value
may become zero, or come close to zero?
Using an absolute error, on the other hand, may fail to disclose similarity and neglecting the severity of the disturbance
Problems of using Metrics for Dynamics
16
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-1000
-500
0
500
0 50 100 150 200
-500.00
0.00
500.00
1000.00
1500.00
2000.00
2500.00
0 20 40 60 80 100 120
Metrics varied for event types Frequency may be less important for a voltage
event and vice versa
Metrics varied on dominant trends and looking forward horizon Criterion evaluating short horizon may fail to
disclose a dominant trend in long horizon and vice versa
Metrics varied on dynamic behaviors involved There is no metrics can capture all dynamic
behaviors, and in most time it can only be picked when you saw it
Example: (on the right) oscillations frequency and magnitude can
be more important than point wise difference along trajectories.
Dynamic Metrics v.s. Events and Variables
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-50
0
50
100
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200
0 50 100 150 200
-60
-40
-20
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0 50 100 150 200
Some Hints of Choosing Criteria
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Making PF and dynamic comparison first
May start with a WECC mapped case
Fixing model problems, improving comparison until it becomes satisfactory
Considering both the time you want to spend and accuracy to achieve
After satisfied with comparison results, reversely select the criteria that you can achieved for comparison
Leave some space for possible variations
As model improves, you should expect a tighter criteria
Power Flow Validation(8/8/2017 Event Example)
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MOD 33 Power Flow Study Process
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Both a large frequency and a large voltage event
2017 8/8 3:08 am PCT
A large frequency event: three Colstrip units tripped
A large voltage event: gen/line tripping, reactor switching, RAS action
CG’s 1st MOD 33 Event
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Time (MDT) Time From Fault Cycles From Fault Event
04:08:18.279 00:00:00.000 0.00 A-Phase fault on Colstrip - Broadview 500 kV Line B; Z=0+ j0.0470 pu 35% from Broadview
04:08:18.329 00:00:00.050 3.00 Fault cleared by opening Colstrip - Broadview 500 kV Line B
04:08:18.647 00:00:00.368 22.08 Series capacitors on the Colstrip – Broadview A line bypassed
04:08:18.687 00:00:00.408 24.48 Colstrip - Broadview 500 kV Line A opens
04:08:18.833 00:00:00.544 33.24 Colstrip Unit 3 Tripped
04:08:18.833 00:00:00.544 33.24 Colstrip Unit 4 Tripped
04:08:18.917 00:00:00.638 38.28 Colstrip Unit 1 Tripped
04:08:23.932 00:00:05.653 339.18 Broadview 500/230 kV Bank 3 tertiary reactors inserted
04:08:28.943 00:00:10.664 639.84 Broadview 500/230 kV Bank 4 tertiary reactors inserted
Data were collected (as needed) along the process, not all at once
Peak RC provided system snapshots in WSM format pre/post event at 03:04 am and 03:10am
NWE provided event sequence
BPA provided PMU data on 43 substations (43 voltage, 43 frequency, 247 line flows)
PSE provided DFR data on 5 substations (5 voltage and 5 frequency)
Snohomish County PUD provided SCADA continuous measurements on one hydro unit (Jackson #2)
Chelan County PUD provided PI continuous measurements on two substations (2 voltage and 2 frequency)
Other utilities provided additional RAS and switching records
MOD 33 Data Collection
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As the first step, WECC helped to develop a mapping planning case from 17HS operation cases, available Dec. 2017
Individual Generation Mapping
Scaled load based on BAs
Major transmission path/branches status mapping
Major switching shunts mapping
Major generator voltage set-point mapping
System wide generation and interchange level matching are hard to be addressed by our regional efforts
MOD 33 Case Preparation 1: WECC efforts
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This is the key step to make sure we are comparing “Apple to Apple”
ColumbiaGrid and member utilities work together to refine the WECC case considering the following aspects:
Generation Mapping
Load Adjustments
Transmission Impedance/Rating/Status Mapping
Reactive Power Devices Mapping
Generator Voltage Set point Mapping
Topology Difference
MOD 33 Case Preparation 2: CG’s efforts
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For refining, we need to identify the difference exists between WECC mapped case and WSM, and improve it
The difference can come from mismatches/errors either in WECC mapped planning case, or WSM case
This is achieved by establishing branch/bus mapping relations between two cases for our region
Using both cases and extra information collected from utilities, an in house software tool automatically setup mappings for 3126 (out of 4989) branches between WSM/planning cases: 0.6kV ~ 500kV
Set up bus mapping for most buses (4086)
Identify topology difference
CG’s Methodology
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The auto-generated table by CG’s tool looks like:
CG’s Methods
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What’s the Difference?
Real Power Comparison
27
MW Generation: Planning vs WSM
Jim Bridger Service Load netted in WSM case
Swing changed to Palo Verde Unit 1, Coulee #22 restored to its WSM value
Stability model changes for synchronous condenser mode of Coulee units
Case Comparison WSM vs planning case
28-50
150
350
550
750
950
1150
1350
1550
1750
-50 150 350 550 750 950 1150 1350 1550 1750
Gen MW comparison
Jim Bridger
Grand Coulee
MW Load: Planning vs WSM
Case Comparison Results
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y = 0.8727x + 0.4804R² = 0.7008
-50
0
50
100
150
200
250
300
350
-50 0 50 100 150 200 250 300 350
MW Load comparison
Grand Coulee
Jim Bridger
Pump is treated as load in WSM, negative generation in Planning case
WECC doesn’t map pump in planning case, treat as normal load to scale with other loads
Same case for several paper mills
Adopted the planning case model for stability simulations
Gen & Load Type Mismatch Example: Coulee Pump
30
MW branch flows are primarily impacted by the following factors:
Generation + load + branch losses + mismatch + topology
Good + ok + negligible + small + ok = ok
3126 (0.6kV ~ 500 kV) branches comparison between planning case and WSM
MW Branch Flow Difference
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y = 0.9624x - 0.1889R² = 0.9776
-200
-150
-100
-50
0
50
100
150
200
-200 -150 -100 -50 0 50 100 150 200WS
M
Planning
What’s the Difference?
Reactive Power Comparison
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Mvar Load: Planning vs WSM
6015 Mvar vs 2092 Mvar
Case Comparison Results
33
y = 0.4817x - 0.6891R² = 0.3551
-40
-20
0
20
40
60
80
100
120
140
-40 -20 0 20 40 60 80 100 120 140
MVar Load comparison
Shunt: Planning vs WSM
-3190 MVar vs. -7203 Mvar
Case Comparison Results
34
y = 0.8794x - 16.681R² = 0.7569
-800
-600
-400
-200
0
200
-800 -600 -400 -200 0 200
Shunt comparison
Marion
Captain Jack
Maple VL
Malin
Celilo
Longview
MVar Generation: Planning vs WSM
-1507 Mvar vs. -2628 Mvar
Case Comparison Results
35
y = 0.8375x - 5.4196R² = 0.5394
-650
-550
-450
-350
-250
-150
-50
50
150
250
350
-650 -550 -450 -350 -250 -150 -50 50 150 250 350
Gen MVar comparison
MVar branch flows are primarily impacted by the following factors:
Generation + load + branch charging (and topology) + shunt + mismatch
Not Good + Not Good + Significant + Not Good + Significant = Not Good
3126 branch comparison between planning case and WSM
MVar Branch Flow
36
y = 0.5541x - 0.865R² = 0.4204
-100
-80
-60
-40
-20
0
20
40
60
80
100
-100 -50 0 50 100WS
M
Planning
Mvar Branch Flow
Improvements:
MW Line Flow Adjustments
37
Step 1, each utility reviews their branch/bus mapping table
Large amount of impedance/rating mismatch found
About 50% of mismatch were errors in WSM case
Some generator/line/breaker status errors in WSM case, as well
Step 2, individual loads mapping (change + move)
MW Line Flow Adjustments
38
y = 1.0001x + 0.006R² = 0.9936
-40
-20
0
20
40
60
80
100
120
140
160
-50 0 50 100 150
MVar Load comparison
y = 0.9998x + 0.319R² = 0.871
-50
0
50
100
150
200
250
300
350
400
-100 0 100 200 300 400
Substation MW Load comparison
Step 3, topology difference review and correction
Step 4, maps outage status, phase shifter angle, transformer tap, series cap bypass status, etc.
Step 5, remove Peak RC’s artificially inserted mismatches in WSM cases, confirmed with utilities’ own measurement data.
MW Line Flow Adjustments
39
PF Comparison Improvements:
Hand-on Example
(no slides)
40
All 3126 branches, 0.6kV ~ 500kV in area 40
MW Flow Comparison WSM vs. planning
41
y = 0.997x - 0.0036R² = 0.9988
-1500
-1000
-500
0
500
1000
1500
-1500 -1000 -500 0 500 1000 1500WS
M
Planning
PLN_vs_WSM
PLN_vs_WSM
Mapping before and after the adjustments
MW Flow Comparison WSM vs. planning
42
y = 0.9624x - 0.1889R² = 0.9776
-200
-150
-100
-50
0
50
100
150
200
-200 -150 -100 -50 0 50 100 150 200WS
M
Planning
MW Branch Flow
y = 0.997x - 0.0036R² = 0.9988
-200
-150
-100
-50
0
50
100
150
200
-200 -150 -100 -50 0 50 100 150 200WS
M
Planning
PLN_vs_WSM
PLN_vs_WSM
500 kV branches
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y = 0.9977x + 0.5159R² = 0.9993
-2000
-1500
-1000
-500
0
500
1000
1500
2000
-2000 -1500 -1000 -500 0 500 1000 1500 2000WS
M
Planning
PLN_vs_WSM
500_low
500_high
Linear (PLN_vs_WSM)
345 kV branches
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y = 1.0242x + 0.4409R² = 0.9999
-400
-300
-200
-100
0
100
200
300
400
-400 -300 -200 -100 0 100 200 300 400WS
M
Planning
PLN_vs_WSM
345_low
345_high
Linear (PLN_vs_WSM)
230kV branches
45
y = 0.9929x + 0.073R² = 0.9971
-1000
-800
-600
-400
-200
0
200
400
600
800
1000
-800 -600 -400 -200 0 200 400 600 800WS
M
Planning
PLN_vs_WSM
230_low
230_high
Linear(PLN_vs_WSM)
115kV branches
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y = 0.9891x - 0.0269R² = 0.9929
-250
-200
-150
-100
-50
0
50
100
150
200
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-250 -200 -150 -100 -50 0 50 100 150 200 250WS
M
Planning
PLN_vs_WSM
115_low
115_high
Linear(PLN_vs_WSM)
Improvements:
Voltage Adjustments
47
Voltage are much more challenging to match than MW line flow, most of them need to be adjusted manually
Line impedance, much more errors in B values than R, X
Shunts come with blocks, not a continuous value to map between cases
Generator voltage set points and Mvar output, most time you can only choose one to match, and impact other parts of the system
Difference in distribution network and topology gives different Var flow
Reactive power doesn’t travel far, you need to match voltage almost piece by piece
Type mismatches exist everywhere. It can take any forms of generator, load, switched shunt, line shunt, SVC. You need to identify them before matching them.
Challenge for Improving Voltage
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Mapped the individual load Mvar value
Align key generator voltage set points, they provides supporting points throughout the network
Review branch mapping table to correct impedance difference
Align Shunts Manually
May neglect some smaller one nested in low voltage level
Starting from 500 kV, tracking down the voltage difference points and fix any model difference causing it
Pay attention to the type mismatches
Load, Gen, SVC, Switched Shunt, Line Shunt, etc.
Steps to Improve Voltage
49
After load scaling and adjustment, type mismatch may show as points off.
MVar Load Improvement
50
y = 0.9845x + 0.1406R² = 0.5281-50
0
50
100
150
200
-50 0 50 100 150 200
Substation Load MVar comparison
Some type mismatches, shunt vs load (gen, line shunt, etc)
Smaller shunts in distribution feeder are not exactly matched
Shunt Improvements
51
y = 1.0121x + 0.0363R² = 0.9579
-800
-600
-400
-200
0
200
-800 -600 -400 -200 0 200
Substation Shunt comparison
Most our members chose to align voltage set points, leave MVar output to whatever values from power flow solution
Generator Mvar Output Improvements
52
y = 0.795x - 0.0946R² = 0.7505
-540
-440
-340
-240
-140
-40
60
160
-600 -500 -400 -300 -200 -100 0 100 200
Substation MVar Gen comparison
All buses in Area 40 (0.6 kV ~ 500 kV)
No correction for voltage discrepancy bellow 115 kV
Voltage Improvements WSM vs planning
53
y = 0.9361x + 0.0676R² = 0.7639
0.9
0.95
1
1.05
1.1
1.15
0.9 0.95 1 1.05 1.1 1.15
WS
M
Planning
PLN_vs_WSM
Linear (PLN_vs_WSM)
500 kV
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y = 0.9066x + 0.0981R² = 0.7966
0.9
0.95
1
1.05
1.1
1.15
0.9 0.95 1 1.05 1.1 1.15
WS
M
Planning
PLN_vs_WSM
500_low
500_high
Linear (PLN_vs_WSM)
230 ~ 345 kV
55
y = 0.9928x + 0.0056R² = 0.9764
0.9
0.95
1
1.05
1.1
1.15
0.9 0.95 1 1.05 1.1 1.15
WS
M
Planning
PLN_vs_WSM
230~345_low
230~345_high
Linear (PLN_vs_WSM)
115 kV
56
y = 0.9395x + 0.0657R² = 0.9328
0.9
0.95
1
1.05
1.1
1.15
0.9 0.95 1 1.05 1.1 1.15
WS
M
Planning
PLN_vs_WSM
115_low
115_high
Linear (PLN_vs_WSM)
MW and Mvar improvements sometimes need to be done iteratively
Linear Regression is a good way to show the comparison for a large amount of points y = ax + b
R2 = c
For line flow: 500kV +: a>0.995, c>0.999
230kV ~ 499kV: a>0.990, c>0.995
115kV ~ 229kV: a>0.985, c>0.990
a+b as close as possible to 1.0
For Voltage
a > 0.9, c > 0.9
Power Flow Experience Summary
57
y = 0.9395x + 0.0657R² = 0.9328
0.9
0.95
1
1.05
1.1
1.15
0.9 0.95 1 1.05 1.1 1.15
WS
M
Planning
PLN_vs_WSM
115_low
115_high
Dynamic Model Validation(8/8/2017 Event Example)
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MOD 33 Dynamic Model Validation Process
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Case Preparation
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Master Dynamic File
Most up to date models submitted by utilities in their original form, no modification or changes from WECC
A large amount of errors
No composite load model
DYD from WECC planning case (suggested)
WECC fixed many errors, while removed/netted some models
Models only in Peak/Light conditions, some may need to be adjusted
Composite load model need to be replaced with data at the event time
DYD from WECC mapped MOD 33 case (used for this MOD 33 study)
Models are further fixed/improved for the event time
A large amount of models being removed
Dynamic Database to Choose
61
In the DYD, WECC has made some adjustments for the dynamic data:
Netted 597 generators for the reason of: renewable, bad models, low loading, etc
84 units were in area 40, sent to utility for confirmation, feedback indicates most units should not be netted
Many other generators with bad models are switched off
A concerns of accuracy as loss of governor response and inertia.
Extra attention needed for events closed to the boarder, where we don’t have other regions to review their generator being netted.
WECC Dynamic Data for 8/8 Event Case
62
Replace the composite load model with 3AM data
Model change for different operating mode (generator/condenser/pump …)
Fixed some errors in stability models
Adopt latest model changes from members
CG’s Further Improvement of Dynamic Data
63
WSM is measurement based, Planning case can adopt other modeling assumptions. The difference may give initialization issues
Service load
Wrong MOD 32 data
Measurement error
Measurement taken in transients
etc.
Flat run may not be very flat
Initialization Issues
64
Two hydro units in Arizona went unstable in our event simulation after 6 seconds:
Model Changes for Operating Modes
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109.89.69.49.298.88.68.48.287.87.67.47.276.86.66.46.265.85.65.45.254.84.64.44.243.83.63.43.232.82.62.42.221.81.61.41.210.80.60.40.20
1.01
1.01
1.01
1.009
1.009
1.008
1.008
1.007
1.007
1.006
1.006
1.005
1.005
1.004
1.004
1.003
1.003
1.002
1.002
1.001
1.001
1
1
0.999
0.999
0.998
0.998
0.997
0.997
0.996
0.996
0.995
0.995
0.994
0.994
0.993
0.993
0.992
0.992
0.991
0.991
0.99
0.99
0.989
0.989
0.988
0.988
0.987
0.987
0.986
Speed, Gen HRSMS4 (15934) #1
gfedcb
Speed, Gen MRMFLT12 (15941) #2
gfedcb
Both units are mapped to negative MW outputs from WSM. WSM capability allows +/- MW output, while planning case only has positive MW capability.
Discussed with Peak RC and USBR, it was confirmed as pumping mode, stability models were updated for the pumping mode.
Model Changes for Operating Modes
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Model Changes for Operating Modes
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109.89.69.49.298.88.68.48.287.87.67.47.276.86.66.46.265.85.65.45.254.84.64.44.243.83.63.43.232.82.62.42.221.81.61.41.210.80.60.40.20
1.0000
1.0000
0.9999
0.9999
0.9998
0.9998
0.9997
0.9997
0.9996
0.9996
0.9995
0.9995
0.9994
0.9994
0.9993
0.9993
0.9992
0.9992
0.9991
0.9991
0.9990
0.9990
0.9989
0.9989
0.9988
0.9988
0.9987
0.9987
0.9986
0.9986
0.9985
0.9985
0.9984
0.9984
0.9983
0.9983
0.9982
0.9982
0.9981
0.9981
0.9980
0.9980
0.9979
0.9979
0.9978
0.9978
0.9977
0.9977
0.9976
0.9976
0.9975
0.9975
0.9974
Speed, Gen HRSMS4 (15934) #1
gfedcb
Speed, Gen MRMFLT12 (15941) #2
gfedcb
Event Analysis
68
Why We Need Event Analysis
69
59.8
59.85
59.9
59.95
60
60.05
0 20 40 60 80 100 120 140
WSM snapshot is saved every 5~6 minutes
When an event happened between 2 snapshots, how confident for you to use the system condition of pre-fault snapshot as the time event happened?
If no major changes (fault, switching of 500 kV line, outage of large power plant, etc. )
If the snapshot is quite close to the time fault happened
Then what if
Event is minutes after the pre-fault snapshot?
Your system is experiencing some changes while
event happens
Using a frequency comparison as example
Simulation nadir < measurement nadir
Load tripping & stall too much?
Other generation tripping elsewhere?
Inertia difference?
Event Analysis
(Steady State)
70
Comparison between 2 WSM snapshots at 3:04am and 3:10am
Event Analysis: Generation
71
-200
0
200
400
600
800
1000
1200
1400
-200 0 200 400 600 800 1000 1200 1400
3:1
0a
m D
isp
atc
h
3:04am Dispatch
Colstrip 1P. Rapids 1
Navajo 1&3
RockyR 7Castic 3
Mica 5
Mica 3
Colstrip 3&4
Generation switched off
Colstrip #1,3,4 (confirmed triggered by events)
Rocky Reach #7 (34.4 MW, out for maintenance at 3:07am, confirmed by Chelan PUD)
Significant generation reduction
Navajo #1&3 (Arizona, -122 MW)
Castaic #3 (pumped storage in LADWP, pre-condensing, post-pumping, -34.7 MW)
Mica #3, 5, 6 (in BCH, -146MW)
Priest Rapids #1 (-21.5 MW, while PR2 + 6.7MW)
Generation increasing
No abnormal generator increasing observed
3:10am was 2 minutes after the events, operators may adjust generators output manually
Using the comparison table can help to track down & add back governor response for units being netted by WECC
Event Analysis: Generation
72
Comparison MW flow between 2 WSM snapshots at 3:04am and 3:10am
Line flow difference mostly related to the events and dispatch changes
Event Analysis: Branch
73
Line Status changes except already involved in the events
Rocky Reach #7 breaker (out for maintenance at 3:07am, confirmed with Chelan PUD)
Switched on Noxon reactor (-51.3Mvar), when ramp up Noxon #5 from condenser mode to 42MW
Switched on Willis capacitor 7.4 Mvar
Switched on Cougar (EWEB) generator unit #2
Switched off Dillons (NWE) capacitor 7.5 Mvar
No significant branch status change in our region between 3:04am ~ 3:10am
Event Analysis: Branch
74
Event Analysis
(Dynamics)
75
Revisit the event sequence where Colstrip units trip
Colstrip ATR Model
76
Time (MDT) Time From
Fault
Cycles From
Fault
Event
04:08:18.279 00:00:00.00
0
0.00 A-Phase fault on Colstrip - Broadview 500 kV Line B; Z=0+ j0.0470
pu 35% from Broadview
04:08:18.329 00:00:00.050 3.00 Fault cleared by opening Colstrip - Broadview 500 kV Line B
04:08:18.647 00:00:00.368 22.08 Series capacitors on the Colstrip – Broadview A line bypassed
04:08:18.687 00:00:00.408 24.48 Colstrip - Broadview 500 kV Line A opens
04:08:18.833 00:00:00.544 32.64 Colstrip Unit 3 Tripped
04:08:18.833 00:00:00.544 32.64 Colstrip Unit 4 Tripped
04:08:18.917 00:00:00.638 38.28 Colstrip Unit 1 Tripped
04:08:23.932 00:00:05.653 339.18 Broadview 500/230 kV Bank 3 tertiary reactors inserted
04:08:28.943 00:00:10.664 639.84 Broadview 500/230 kV Bank 4 tertiary reactors inserted
Simulation of ATR model
77
Contingency Name Cycles From Fault Event
August_8_events 37 Colstrip Unit 2 Tripped
August_8_events 38 Colstrip Unit 3 Tripped
August_8_events 41 Colstrip Unit 4 Tripped
Remove ATR, manually Add Tripping
78
Keeler SVC connected 230 kV and 500 kV buses simulation shows a much higher post fault voltage
Keeler SVC Post Fault Voltage
79
1.018
1.02
1.022
1.024
1.026
1.028
1.03
1.032
-100 -50 0 50 100 150 200 250 300 350
Time
1.06
1.062
1.064
1.066
1.068
1.07
1.072
1.074
1.076
-100 0 100 200 300 400
Time
All nearby reactors have already on pre-fault, and the SVC is at 70 Mvar capacitive, selected to switched off during contingency
230 kV voltage drop too low, all buses voltage show a much slower ramp rate (not right)
It implied the SVC should be on, but the dynamic performance may not be accurate in simulation
Is the SVC tripped?
80
1.005
1.01
1.015
1.02
1.025
1.03
1.035
-100 -50 0 50 100 150 200 250 300 350
Time
1.056
1.058
1.06
1.062
1.064
1.066
1.068
1.07
1.072
1.074
1.076
-100 0 100 200 300 400
Time
Adding a dummy reactor (-30Mvar) and switched in during the fault
The voltage/ramp rate matches well, may suggested SVC post-fault Mvar should be 30Mvar less
Post fault SVC Output
81
1.016
1.018
1.02
1.022
1.024
1.026
1.028
1.03
-100 -50 0 50 100 150 200 250 300 350
Time
Switching and voltage discrepancy (low simulated voltage) observed in east side
Reactive Switching in East Side
82
1
1.01
1.02
1.03
1.04
1.05
1.06
1.07
1.08
-100 0 100 200 300 400
Time
Bell 230kV
0.9
0.95
1
1.05
1.1
1.15
1.2
-100 0 100 200 300 400
Time
Garrison 500kV
1
1.02
1.04
1.06
1.08
1.1
1.12
1.14
1.16
-100 0 100 200 300 400
Time
Taft 500kV
A RAS action should be modeled to switch out Garrison Reactor (-218.3Mvar) after 5 cycles of Colstrip line tripping
A much better post transient voltage match for 4 second
Two additional steps for switching observed (reverse direction), using the Noxon reactors (2 step@ -50 Mvar), no stability model but switched in through contingency
Reactive Switching in East Side
83
0.9
0.95
1
1.05
1.1
1.15
1.2
-80 -60 -40 -20 0 20 40
Time
Garrison 500kV
GARR 500 B1 SA .B500EAST_____1VP VPM kV GARR 500 B1 SA
GARRISON_500.0_TSBusVinKV
Bell 230 kV voltage now matched perfectly, not enough for Garrison and Taft.
AVA confirmed Noxon reactors switching using the recorded data
Reactive Switching in East Side
84
1
1.02
1.04
1.06
1.08
-100 0 100 200 300 400
Time
Bell 230 kV
BELL 230 B1 SA .B230SECT1____1VP VPM kV BELL230 B1 SA
'BELL S0_230.0'_TSBusVinKV
0.9
0.95
1
1.05
1.1
1.15
1.2
-80 -60 -40 -20 0 20 40
Time
Garrison 500kV
GARR 500 B1 SA .B500EAST_____1VP VPM kV GARR500 B1 SA
GARRISON_500.0_TSBusVinKV
Dynamic Comparison in PMU/DFR/PI/SCADA
(in pdf and Excel)
85
Dynamic Comparison Discrepancy
86
Frequency nadir: simulation higher than PMU
Lower inertia in simulation, should results in lower nadir of simulation
Confirmed no other related generator tripping during the events except Colstrip
Load model becomes the most likely reason, utilities is working on improving load composition
Frequency Dip
8759.8
59.85
59.9
59.95
60
60.05
-100 -50 0 50 100 150 200 250 300 350
Fre
q
Time
At the time of fault, PDCI was ramping down its MW flow
A coincidental change that help to relief impact from Colstrip tripping
A more accurate MOD 33 simulation should include a model to mimic the flow ramping.
PDCI Flow Change During the Fault
88
3.7
3.75
3.8
3.85
3.9
3.95
4
4.05
4.1
-100 -50 0 50 100 150 200 250 300 350
'BIG EDDY_500.0' CELILO1_500.0 1_TSACLineFromP
BGED 500 B1 SA .A500CELILO___1MW
'BIG EDDY_500.0' CELILO1_500.0 1_TSACLineFromP
PMU shows a flow increase on Longvanx to Mintfarm 230kV line
PSE’s Mint Farm’s gas turbine was set as “base load” at Pmax. PSE provided a new Gas governor model validated in March, it shows a significantly increased capability. This governor model will be updated by PSE in their future modeling data submission
Line Flow around Longview
89
-2.75
-2.7
-2.65
-2.6
-2.55
-2.5-100 -50 0 50 100 150 200 250 300 350
LONGVANX_230.0 MINTFARM_230.0 1_TSACLineFromP
LONG 230 B2 SA .A230MINTFARM_1MW
LONGVANX_230.0 MINTFARM_230.0 1_TSACLineFromP
PMU shows a flow increase on McNary S1 to Ph2 line
MCN#1 is off, MCN#2 is on with a IEEE_G3 governor model. May either switching on MCN#1 and ramp up the power, or imply a wrong governor response for #2.
USACE confirmed a recent updated the governor to H6E model, provide to BPA in August.
Line Flow around McNary
90
-0.7
-0.6
-0.5
-0.4
-0.3
-0.2
-0.1
0-100 -50 0 50 100 150 200 250 300 350
'MCNRY S1_230.0' 'MCN PH2_230.0' 2_TSACLineFromP
MCNY 230 B1 SA .A230MCNARYPH_2MW
'MCNRY S1_230.0' 'MCN PH2_230.0' 2_TSACLineFromP
Coulee # 19 switched from condenser model to generator mode due to low frequency ~ 270 seconds later
Anybody knows why it absorbing more power (-15MW -> -30MW) before it starts to generate? (Gate control? Motor starting? … )
Switching from Condenser to Generator
91
-0.2
-0.1
0
0.1
0.2
0.3
0.4
-100 -50 0 50 100 150 200 250 300 350
COULEE_500.0 COULEE19_500.0 1_TSACLineFromP
GCFI 500 B1 SA .A500GEN19____1MW
COULEE_500.0 COULEE19_500.0 1_TSACLineFromP
R1.3: Which dynamic comparison are acceptable, or not?
R1.4: If not, how can we resolve them?
MOD-33 Compliance Requirements
92
Load model improvement (very very long time)
Gen/Excitation model validation (MOD-26, 0~5 years)
Governor model validation (MOD-27, 0~5 years)
New model development (PDCI ramping, condenser control mode switching etc., several months)
Adjustments to existing model (parameters, settings, mode, etc., days ~ months)
+
Software issues (random time)
Measurement issues (random time)
So far, to resolve “Unacceptable Discrepancy”
93
Other Usage for MOD 33 Case: MOD 26 Example
94
SCADA data sampled 1Hz for Ifd, Efd, Vt, P & Q,
Snohomish Jackson U2
95
560
570
580
590
600
610
620
630
-150.00 -100.00 -50.00 0.00 50.00 100.00 150.00 200.00
Jackson U2 Ifd
U2_AVR.GeneratorFieldCurrent
JACKSN2_13.80 1_TSGenIfd
60
80
100
120
140
160
-200.00 -100.00 0.00 100.00 200.00
Jackson U2 Efd
U2_AVR.GeneratorFieldVoltage
JACKSN2_13.80 1_TSGenFieldV
-4
-3
-2
-1
0
1
-200.00 -100.00 0.00 100.00 200.00
Jackson U2 Mvar
U2_AVR.GeneratorMegavars
JACKSN2_13.80 1_TSGenQ
13.75
13.8
13.85
13.9
13.95
14
14.05
14.1
14.15
-200.00 -100.00 0.00 100.00 200.00
Jackson U2 Vterm
U2_AVR.GeneratorTerminalVoltage
JACKSN2_13.80 1_TSGenTermVPU
Other Usage for MOD 33 Case: MOD 27 Example
96
4 co-gen units connected to a 115kV substation in Puget Sound Energy. DFR installed in 115kV substation (high side of GSU), no direct measurements on plant terminal
Current from Unit 1 (lower side of GSU) can be derived from current (vector summation) on breaker 3192 and 3194.
DFR in 115kV substation
97
Phase current magnitudes in Amps are measured by DFR, no phase angle available:
3192 current >> 3194 current; 3194 current is constant before & after fault
Use 3192 current to approximate generator current from unit #1
DFR Current
98
185
190
195
200
205
210
215
0 20 40 60 80 100 120 140
3192 IA
23.5
24
24.5
25
25.5
26
26.5
27
27.5
28
0 20 40 60 80 100 120 140
3194 IA
Simulation vs DFR
A good match for pre-fault and first spike current in magnitude
DFR shows unit #1 settled to about 8 amps phase current higher, while simulation keep the current flat
DFR Current
99
180
185
190
195
200
205
210
215
0 10 20 30 40 50 60
Gen 1 Current comparison
3192 IA
Simulation from Gen 1
CG and PSE reviewed the modeling & test reports
2011 original modeling report, 2013 model validation report, 2017 MOD26&27 report
Confirmed the stability models in used are consistent with the reports
Believe a wrong trate value is used. Set trate = 39.5, and governor response limit to “normal”, re-run the simulation
Existing Modeling Document Review
100
180
185
190
195
200
205
210
215
0 20 40 60 80 100 120 140
Gen 1 Current comparison
GO needs to validated their generators every 5 years
Can use either system events or staged tests
MOD 33 case is a system event case
Some reasons you may want to check MOD 33 case for exciter/governor modeling verification
Staged tests doesn’t verify you a full list of parameters
Model parameters (performance) may vary under different conditions (temperature, loading, operating mode, etc.)
Always good to check periodically for your machine models
TO may raise the question to GO if some discrepancy found
Verify the models from consultants
System event validation complement but not fully replace staged tests
NERC MOD 26/27
101
