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ArizonaStateUniversity
Report 4
SecurityAssessmentofthePlanned
WesternInterconnection
For the Years 2020 and 2022
April 2013
Jaime Quintero
Vijay Vittal
Gerald Heydt
Hui Zhang
ii
Summary
This is a technical report presented to the Western Electricity Coordinating Council
(WECC) as a concluding engineering summary of system wide security for 2020 – 2022. The
work was done under a subcontract DE-OE0000423-001 from WECC to the Arizona State
University. The entire project is part of the American Recovery and Reinvestment Act.
The aim of this report is to present preliminary results for a system-wide security
assessment of the mid-term planned Western Interconnection transmission system with high
penetration of wind and solar generation for years 2020 and 2022. The presented approach
articulates the static security analysis and the dynamic security analysis in an efficient way
applicable to bulk power systems and from the regional planner perspective. This work also
shows some of the stability challenges presented in future expanded transmission power
systems due to conventional synchronous generation retirement and renewable generation
deployment.
The first part of this report is the static security assessment of the planned base cases.
The two base cases were obtained from WECC and they are the heavy summer case for year
2020 and the planned light spring case for year 2022. The static security assessment in this
report focuses on the identification and mitigation of static critical contingencies, defined here
as the N – 1 type contingencies that collapse the system at the original operating point,
provided all voltages and flows in the transmission system are initially under limits.
The dynamic security assessment of the two cases for years 2020 and 2022 is the main
focus of the second part of this report. The dynamic assessment is developed in two steps, a
small stability analysis and a transient stability analysis, provided the system is secure in the
static sense. In the small signal stability analysis, an identification and comparison of the main
interarea modes of the Western Interconnection is obtained through the years 2010, 2020 and
2022. It is also shown how the integration of Converter Control Based Generators (CCBG) and
the retirement of synchronous generators affect the modes of oscillation and how these new
devices interact with the rest of the system in the small signal stability sense.
The transient stability analysis of the transmission system is developed under two
different criteria in order to identify credible dynamic critical contingencies in a bulk power
system. The first criterion is to look for dynamic issues starting from the previous identified
static critical contingencies and the second one is to examine actual stability limited path
ratings from previous operational cases. The approach seems to be effective in identifying
dynamic critical contingencies in bulk power systems.
iii
Some corrective actions for the security issues found are presented and tested. The aim
of these solutions is to provide some insight into potential alternatives to mitigate the problems
found. Moreover, some remedial actions may be necessary to mitigate dynamic security issues.
iv
Table of Contents
Summary ....................................................................................................................................................... ii
I. Introduction .......................................................................................................................................... 1
II. Static Security Assessment.................................................................................................................... 4
Static Critical Contingencies (SCC) ............................................................................................................ 4
III. Dynamic Security Assessment .......................................................................................................... 7
Small Signal Stability Analysis ................................................................................................................... 8
Transient Stability Analysis ..................................................................................................................... 19
The First criterion for Identifying DCC ................................................................................................ 19
The Second criterion for identifying DCC ............................................................................................ 26
IV. Conclusions ..................................................................................................................................... 33
V. References .......................................................................................................................................... 35
VI. Appendices ...................................................................................................................................... 37
Appendix A: Identified Renewable Generators ...................................................................................... 37
Appendix B: Selected Modes .................................................................................................................. 37
Appendix C: Selected Additional Modes ................................................................................................. 37
Appendix D: Dynamic Issues from First criterion .................................................................................... 37
Appendix E: Dynamic Issues from Second criterion ............................................................................... 37
v
List of Figures
Fig. 1. Flow chart of the integrated security assessment approach ............................................................ 3
Fig. 2. Kemano mode response to selected control parameters’ variations ............................................. 18
Fig. 3. Wind 12 mode response to selected control parameters’ variations ............................................. 18
Fig. 4. Bus voltage dips due to the event including branch ‘41135 41136 (1)’ or branch ‘40537 41135
(1)’ ............................................................................................................................................................... 21
Fig. 5. Generator rotor angles due to the event including branch ‘64004 64074 (1)’ ............................. 21
Fig. 6. Generator active power oscillations due to event including branch ‘64005 64248 (1)’ or branch
‘64045 64248 (1)’ ....................................................................................................................................... 22
Fig. 7. Generator rotor angles due to the event including branch ‘BOARD T2 230.0 to MCNRY S2 230.0
(1)’ ............................................................................................................................................................... 24
Fig. 8. Generator rotor angles due to the event above, and after PSS’s tuning ........................................ 24
Fig. 9. Generator rotor angles due to the event including branch ‘DR E TP 230.0 to DALREED 230.0
(1)’ ............................................................................................................................................................... 25
Fig. 10. Generator rotor angles due to the event above, and after tuning action .................................... 25
Fig. 11. Generator active power oscillations due to the event at Path 43 ................................................ 27
Fig. 12. Generator rotor angles due to the event at Path 8. ...................................................................... 28
Fig. 13. Generator rotor angles due to the event at Path 65. .................................................................... 28
Fig. 14. Generator rotor angles due to the event at Path 8. ...................................................................... 31
Fig. 15. Bus frequency oscillations due to the event at Path 8. ................................................................. 31
Fig. 16. Generator 24155 poor damped oscillations due to the event at Path 66. ................................... 32
Fig. 17. After tuning generator 24155 damped oscillations due to the event at Path 66. ........................ 32
vi
List of Tables
TABLE I 2020 and 2022 Planned Base Cases ................................................................................................. 2
TABLE II Static Critical Contingencies for the 2020 Planned Case ................................................................ 5
TABLE III Static Critical Contingencies for the 2022 Planned Case ............................................................... 6
TABLE IV WECC Interarea Modes and CCBG Modes in the 2010 and 2020 Base Cases ............................... 9
TABLE V WECC Interarea Modes and CCBG Modes in the 2010 and 2022 Base Cases .............................. 10
TABLE VI Synchronous Generators Replaced by Wind Generators ............................................................ 12
TABLE VII Wind Generators Replaced by Synchronous Generators ........................................................... 13
TABLE VIII Sensitivities of Interarea Modes and Wind Plant Local Modes for the 2022 Case .................... 15
TABLE IX Kemano Mode Response to Tuning Parameter Variations .......................................................... 16
TABLE X Wind 12 mode Response to Tuning Parameter Variations ........................................................... 17
TABLE XI Dynamic Response to Previously Identified SCC for Case 2020 ................................................... 20
TABLE XII Corrective Actions to DCC Identified with Criterion 1 for Case 2020 ......................................... 22
TABLE XIII DCC identified with First Criterion for Case 2022 ...................................................................... 23
TABLE XIV Stability Limited Path Ratings .................................................................................................... 26
TABLE XV Dynamic Response to Events from Second Criterion in the 2020 Case ..................................... 27
TABLE XVI Corrective Actions to Dynamic Critical Contingencies for Case 2020 ........................................ 29
TABLE XVII Dynamic Response to Events from Second Criterion in the 2022 Case ................................... 30
1
I. IntroductionThe continuous evolution of the interconnected power systems, the imposed economic
operating and planning criteria, and the expected high penetration of renewable generation
resources tend to create more complex, potentially unpredictable and more stressed power
systems. Renewable Portfolio Standards (RPS) and financial incentives in the US, China,
European Union (EU) and Japan [1] - [3] are providing the legal and economic incentives to
reach targets of 15 to 30 percent of total electricity generation by the year 2020. The change to
the generation mix is impacting the reliability of the interconnected power system.
The inherent unpredictable behavior of wind and solar generation, their reduced inertia,
synchronizing torque and reactive power support have shown to affect the stability limits of the
power system [4], [5]. Moreover, the effects of the integration of wind and solar generation on
the overall stability of the system have not been clearly described yet, and there are discordant
results in the literature [6], [7]. Through the proposed static and dynamic security assessment
approach, this work describes potential system-wide stability problems due to the expansion of
the current transmission system, the retirement of conventional generators and the integration
of renewable generation.
In this work, the test bed data was obtained from the Western Electricity Coordinating
Council (WECC) [8]. They are three base cases: One is the heavy summer 2010 operating case
and the other two cases are based on horizon studies for years 2020 and 2022, including
numerous updates to the transmission, generation and load. The horizon studies were
completed using the production cost model program PROMOD IV [9]. Foundational
transmission and generation expansion projects presented by the stakeholders with a high
likelihood of being in service by 2020 and 2022 were incorporated in the planned cases. Around
17% of the total generation is provided by renewable sources such as wind and solar in order to
comply with the Renewable Portfolio Standards (RPS) requirements. The first planned case
selected for this work is the case that reflects the load level projected for heavy summer
conditions in 2020. The second one is the planned case for light spring 2022 conditions. They
are both described in Table I.
2
TABLE I 2020 AND 2022 PLANNED BASE CASES
2020 2022
Case name promod
2020_v17_pmax _mva_fixed2_ed.sav
22lsp1sa.sav
Buses 17,530 19,745 Branch Sections 15,369 16,430 Transformers 7,092 8,018 Generators 3,885 4,461 Loads 8,590 9,147 Shunts 1,508 1,621 Static VAR devices 1,043 1,148 DC buses 20 22 DC lines 13 16 Generation (MVA) 178,059 + j11,303 121,306 + j2,989 Load (MVA) 172,634 + j36,299 117,137 + j27,278 Shunt (MVAr) j19,452 j7,308
Svd (MVAr) j8,924 j2,228
Transmission expansion planning (TEP) considering power system operational aspects is
based on production cost models. The goal of TEP is to minimize total cost while keeping the
model size and the computational burden under certain limits in order to reach an optimal
solution [10]. Recent works have shown efforts to include security constraints within the
optimization problem with potential practical applications, as in [10] - [13], where thermal
violations, static voltage limits, small signal and transient stability constraints have been
considered. However, the optimization procedure is generally based on static and dynamic
modeling simplifications. Therefore, the security of the solutions obtained should be validated
by a comprehensive system-wide plan as presented in this work.
The proposed approach complies with North American Electric Reliability Corporation
(NERC) standards [14] – [16] and is described in Fig 1. A static security assessment is performed
in order to identify static critical contingencies and static limits, provided voltage and flow
violations are cleared at the original operating point. Static critical contingencies (SCC) in this
work are defined as N – 1 contingencies that make the system collapse at the original operating
point. Corrective actions are applied. Next, the dynamic security assessment is carried out over
the resulting static secure case, including both a small signal stability analysis and a transient
stability analysis.
In the small signal stability analysis, generators related with unstable oscillations are
tuned properly. Traditional and previously identified interarea modes in the Western
3
Interconnection are followed and described through cases 2010, 2020 and 2022. A special
emphasis on describing the effect of new renewable generators on current electromechanical
interarea modes is given. Also new modes related to Converter Control Based Generators
(CCBG), as doubly fed induction generators and full converter generators, are identified and
described. Finally, a transient stability analysis is performed over the static secure cases
considering previously identified static critical contingencies and historical stability limited
transmission paths. In this way, the number of potential dynamic critical contingencies to be
analyzed is effectively reduced to a practical number, for the bulk power system.
Fig. 1. Flow chart of the integrated security assessment approach
4
II. StaticSecurityAssessmentPre-contingency and N – 1 contingency steady state conditions were analyzed using the
Steady-State Analysis Tools (SSTOOLS) [17] integrated in the commercial power system
simulation tool PSLF [18] and also the Voltage Security Assessment Tool (VSAT) [19], which is a
simulation module of the DSATools [20] developed by Powertech Labs. The N – 1 contingency
analysis includes outage of every branch that is above 100 kV (or transformers with both sides
above 100 kV) and every generating unit that is above 500 MW. The study covered a broad
range of operating conditions from the base case to more stressed conditions using VSAT. A
complete report of this process applied to base case 2020 was presented to WECC in Report 3
[21].
Contingencies from this previous study that collapsed the system under base case
operating conditions were identified as critical contingencies. These results were double
checked manually using Powerflow and Short-circuit Analysis Tool (PSAT) [22] another
DSATools’ module, and PSLF. Those contingencies that were revalidated as critical, using these
other two programs, are defined here as the static critical contingencies for years 2020 and
2022.
Static Critical Contingencies (SCC)
Table II and Table III show the identified SCC for the planned 2020 and 2022 cases. In
addition, the corrective actions applied to eliminate the risk are presented. Notice that, some
existing branches became congested due to the generation expansion. Also, due to the
retirement of high CO2 emission plants and the high penetration of renewables with limited VAr
support in some areas, additional reactive power compensation was necessary at certain buses.
For those cases where the transmission capacity becomes insufficient after the load
increase or the generation expansion in 2020 and 2022 cases, a TEP process may be applicable.
However, for the cases presented in Table II and Table III, a TEP algorithm as presented in
previous works [10], [23] was not applied. This was because the involved circuits were mostly
radially connected load centers or new generation plants and therefore, finding a solution for
these cases was trivial.
The proposed corrective actions showed to be effective in making the system converge
and neutralizing the described problems caused by the contingencies.
5
TABLE II STATIC CRITICAL CONTINGENCIES FOR THE 2020 PLANNED CASE
Area N – 1 Branch Outage (Circuit Number) Corrective Actions
14 Line 14234 14230 (1) Double line added: 14234 14230 2
30
Line 30250 30261 (1) Phase shifting transformer switched out: 30250 30255 1
Line 30261 30300 (1) Converged after better area reactive generation support
Line 30879 30881 (1) Double line added: 30879 30881 2
40
Line 40193 45007 (1) 50 MVAr shunt reactive compensation added at 45203
Line 41136 45007 (1) This is part of a radial 115 kV path, with the two ends connected to the 230 kV buses. A Parallel circuit is added from 40537 to 45007
Line 41135 41136 (1)
Line 40537 41135 (1)
Line 40874 44958 (1) Double line added: 40874 44958 2
Line 47123 40440 (1) Double line added: 47123 40440 2
50 Line 50782 50786 (1) Double line added: 50782 50786 2
54
Generator 55348 (1) Converged after improving reactive generation support in this area
Line 54304 54305 (28) Converged after improving reactive generation support in this area Line 54304 54417 (28)
Line 55164 55165 (57) Only feeder to load center (69 kV). Parallel circuit added from 55164 to 55166 Transf. 55165 55169 (1T)
Line 55229 55234 (49) Double line added: 55229 55234 2
Transf. 55484 57484 (1T) Reactive compensation at bus 55463 increased. Transf. 55485 57484 (1T)
Transf. 55491 57491 (T1) Reactive compensation at bus 55498 increased.
64
Line 64004 64074 (1) This becomes a main outlet circuit for new generation in the zone. Parallel circuit added from 64074 to 64045
Line 64005 64248 (1)
Line 64045 64248 (1)
6
TABLE III STATIC CRITICAL CONTINGENCIES FOR THE 2022 PLANNED CASE
Area N - 1 Branch Outage (Circuit Number) Corrective Actions
40
Line BOARD T2 230.0 to MCNRY S2 230.0 (1)
This is a congested circuit. Line 45162 to 45075 is overloaded. A parallel circuit is added from bus 41352 to bus 45162.
Line BOARD T2 230.0 to DR E TP 230.0 (1)
Line DR E TP 230.0 to DALREED 230.0 (1)
Line DR W TP 230.0 to DALREED 230.0 (1)
Line DR W TP 230.0 to JONESCYN 230.0 (1)
Tran LAPINE 230.0 to LAPINE 115.0 (1) Existing SVD activated
Line POMEROY 115.0 to TUCANN R 115.0 (1) Weak link. Parallel circuit added from bus 48253 to bus 41400
Line TUCANN R 115.0 to WALAWALA 115.0 (1)
Converges, after reducing line reactance from bus 40835 to bus 40239, to 0.0394 pu
Line MCNRY S1 230.0 to MCNRY S2 230.0 (1) SVD added at bus 41352
50
Line SKA 287 287.0 to MIN 287 287.0 (1) Double line added: 50456 50458 2
Line MIN 287 287.0 to KIT 287E 287.0 (1) Double line added: 50458 80768 2
Tran NTL 138 138.0 to NTL 1V1 138.0 (1) Reclosing does not converge. Transformer fixed taps edited.
60 Line QUARTZ 138.0 to WJOHN DY 138.0 (1) Double line added:60305 61835 2
64
Line ANACONDA 120.0 to MILLERS 120.0 (1) Main outlet circuit for new generation in the zone. Parallel circuit added from 64074 to 64045
Tran ANACONDA 230.0 to ANACONDA 120.0
Line ANACONDA 230.0 to ROUNDMTN 230.0 (1)
Line FRONTIER 230.0 to ROUNDMTN 230.0 (1)
65 Line YELOWTLP 230.0 to YELOWBR 230.0 (1) Recurrent weak link from year 2010 case (also in year 2020 case). Double line added: 66750 73229 2
70 Line BOONE 230.0 to LAMAR_CO 230.0 (1) Main outlet circuit for increased generation in the zone. Double line added: 70061 70254 2
7
III. DynamicSecurityAssessmentThe dynamic security assessment is applied over the statically secured systems for years
2020 and 2022 obtained in the above section. The assessment is addressed utilizing two
avenues of analysis: A small signal stability analysis and a transient stability analysis. In the first
avenue, traditional Western Interconnection interarea modes are identified and compared to
the operational 2010 base case. New wind plant control modes associated with converter
control based models emerge, and some characteristics such as mode shape and parameter
sensitivity are described and compared to traditional electromechanical modes. Also
interaction in the small signal stability sense, between synchronous generators and Converter
Control Based Generators (CCBG) is analyzed.
The transient stability analysis includes the dynamic response of the planned system to
the N - 1 SCCs that were previously identified and corrected earlier in the static security
assessment. Also, the dynamic response to well-documented N – 1 and N – 2 contingencies that
set dynamic stability limits for some of the WECC path ratings in the actual system are analyzed.
Some potential corrective actions are presented through the analyses. However, some
dynamic issues identified in the transient stability study may require the implementation of
remedial actions that are outside the scope of this work. Nevertheless, this articulated
approach between the static and dynamic security assessment considering previous and
credible information on the weaknesses of the system, seems to be effective in reducing the
number of dynamic critical contingencies to be analyzed in the planned cases.
Dynamic data of planning cases 2020 and 2022 include new machine models with
respect to the 2010 operating case for modeling renewable generation. The authors of this
report identified in both horizon cases the use of the Vestas V80 induction generator model
‘genwri’, the doubly-fed asynchronous generator models ‘gewtg’ and ‘wt3g’, and the full
converter generator model ‘wt4g’ to represent renewable generation. Also, for year 2020 case
some wind generators and renewables are represented using the synchronous generator model
‘gentpj’, while for year 2022 case wind generators models ‘wt1g’ and ‘wt2g’ are included in
some cases.
Appendix A shows the specifications of the identified renewable generators models for
years 2020 and 2022 cases, including the total power generated by each model type. Notice
that the total identified renewable generation in case 2020 accounts for just the 6.13% of the
total generation, while in case 2022 it accounts for almost 15%. This is due to the use of
different models than the standard ones to represent renewable generation in case 2020.
8
Small Signal Stability Analysis
Interarea modes were identified using mode shapes generated by the Small Signal
Stability Tool (SSAT) [24], which is another simulation tool from DSATools
. Table IV and Table V
present the main interarea electromechanical modes found in the planned 2020 and 2022 base
cases, compared to the 2010 operating case. The converter control based generators (CCBG)
participation index is calculated for each interarea mode. This index is obtained from state
variables with participation factors (pf) greater than 0.1. The numerator is the addition of pf
related to CCBG’ state variables and the denominator is the total of all the selected pfs. Notice
that, some interarea modes are referenced by their names as known in the literature [25],
while wind plant modes are given specific names.
As seen in Table IV, two well documented modes of the Western Interconnection
Kemano and Colstrip do not show up in the planned 2022 case. Also, it may be noticed that two
new interarea modes emerge in the 2020 case. In the planned 2022 case, the Southwest mode
is not presented as shown in Table V. A shared characteristic of these interarea
electromechanical modes is that the participation of CCBG’ state variables is very small in the
2020 case and zero in most of the 2022 interarea modes. This may be expected in the 2020 case
due to the fact that they account for only 2.74% of total generation according with Appendix A.
However, in case 2022 CCBG provide the 13.20% of total generation and their participation in
the electromechanical modes is even lower comparing Tables IV and V.
The complete lists of participating state variables and mode shapes for the modes
included in Tables IV and V are presented in Appendix B. Notice also from Appendix B that, all
CCBG participating in the electromechanical modes in case 2020 are double fed induction
generator models ‘wt3g’, while all of the CCBG participating in the interarea modes in 2022 are
full converter controlled models ‘wt4g’. All ‘wt3g’ and ‘wt4g’ models are set to operate in
reactive power control mode and as may be seen from Appendix B, the only CCBG parameters
with participation factors greater than 0.1 in the identified modes are the reactive control
integral gain and the voltage control integral gain.
These results tell us that under the current modeling selections in the planned 2020 and
2022 cases, the participation of full converter generators in electromechanical modes is even
lower than the participation of partial converter controlled generators.
9
TABLE IV WECC INTERAREA MODES AND CCBG MODES IN THE 2010 AND 2020 BASE CASES
Interarea Mode 2010 2020
Num Name f (Hz) ζ (%) Interarea
Index Simi. Index
CCBG Particip.
Areas f (Hz) ζ (%) Interarea
Index Simi. Index
CCBG Particip.
Areas
1 PACI (COI)
0.226 12.27 487 / 2442 1 0 / 39.94 North
vs. South
0.254 19.46 -- 0.3 2.64 / 49.33 Canada vs. Arizona &
Mexico
2 Alberta 0.342 9.89 805 / 2442 0.16 0 / 25.8 Alberta vs. B.C. & NW
0.3721 10.9 922 / 2944 1 0.65 / 7.21 Alberta vs. B.C. & NW
3 Southwest 0.8114 11.15 112 / 2442 1 0 / 50.73 SW vs. SE 0.877 11.22 110 / 2944 0.07 0 / 69.66 SW vs. SE
4 -- 0.517 14.23 670 / 2442 1 0 / 83.06 B.C. vs.
PG&E & NW 0.541 9.43 767 / 2944 0.1 0.5 / 36.84
B.C. vs. PG&E & NW
5 Kemano 0.606 12.61 580 / 2442 -- 0 / 58.31 B.C. vs.
Pace
6 Colstrip 0.637 11.29 126 / 2442 -- 0 / 36.37 B.C., Pace & Sierra vs. S.C.
& NW
7 --
0.39 12.36 225 / 2944 -- 0.53 / 6.48 S.C. vs. East
8 --
0.627 10.63 409 / 2944 -- 0.35 / 42.34 Arizona -
Calif. & B.C.
9 -- 0.7 11.18 198 / 2442 -- 0 / 19.16 PG&E vs. S.C.
10 Wind 10 0.361 10.5 -- -- 2.91 / 2.91 Alberta vs. B.C. & NW
1 At the original 2020 case, mode Wind 10 overlaps Alberta mode.
Interarea Index: m generators with speeds with real part of the mode's right eigenvector larger than 0.2 / n total generators
Similarity Index: Normalized index comparing the mode shape against the mode shape's reference in the same row CCBG Participation Index: ∑ participation factors larger than 0.1 and related to CCBG's state variables / ∑ participation factors larger than 0.1
Total Wind Contribution: ∑ Generators' power outputs in the wind participation index
10
TABLE V WECC INTERAREA MODES AND CCBG MODES IN THE 2010 AND 2022 BASE CASES
Interarea Mode 2010 2022
Num Name f (Hz) ζ (%) Interarea
Index Simi. Index
CCBG Particip.
Areas f (Hz) ζ (%) Interarea
Index Simi. Index
CCBG Particip.
Areas
1 PACI (COI)
0.226 12.27 487 / 2442
1 0 / 39.94 North
vs. South
0.305 19.72 343 / 2044 0.2 0 / 73.21 Canada vs. Arizona &
Mexico
2 Alberta 0.342 9.89 805 / 2442
0.11 0 / 25.8 Alberta
vs. B.C. & NW
0.471 12.16 527 / 2044 1 0 / 4.39 Alberta vs.
B.C. & Colorado
3 Southwest 0.8114 11.15 112 / 2442
1 0 / 50.73 SW vs. SE
4 -- 0.517 14.23 670 / 2442
1 0 / 83.06 B.C. vs.
PG&E & NW 0.622 5.92 65 / 2044 0.14 0.85 / 30.99
B.C. vs. PG&E
5 Kemano 0.606 12.61 580 / 2442
0.09 0 / 58.31 B.C. vs.
Pace 0.669 13.39 237 / 2044 1 0 / 10.21
B.C. vs. Pace &
PSColorado
6 Colstrip 0.637 11.29 126 / 2442
0.1 0 / 36.37 B.C., Pace & Sierra vs. S.C.
& NW 0.838 9.37 152 / 2044 1 0 / 31.32 West, NE
9 -- 0.7 11.18 198 / 2442
1 0 / 19.16 PG&E vs. S.C.
11 Wind 11
0.588 6.85 -- 1 4.48 / 4.48 PG&E, Arizona
12 Wind 12 0.607 28.28 -- 1 6.93 / 9.62 SC, S.Diego,
Arizona
Interarea Index: m generators with speeds with real part of the mode's right eigenvector larger than 0.2 / n total generators
Similarity Index: Normalized index comparing the mode shape against the mode shape's reference in the same row CCBG Participation Index: ∑ participation factors larger than 0.1 and related to wind generators' state variables / ∑ participation factors larger than 0.1
Total Wind Contribution: ∑ Generators' power outputs in the wind participation index
11
One wind plant local mode for the 2020 case and two wind plant local modes for the
2022 case are included in Tables IV and V. All of these three modes involve mostly the
participation of CCBG’ state variables. Wind 10 mode in case 2020 includes only two generators
with participations factors greater than 0.1, they both are ‘wt3g’ models. Wind 11 and 12 in
case 2022 includes mostly the participation of type ‘wt4g’ models, with some participation of
synchronous generators type model ‘gentpj’ in mode Wind 12. However, considering the mode
shape and the participation factor magnitude of the involved generators in these wind modes,
none of them may be considered interarea.
The local characteristic and low interaction with synchronous generators of the
introduced CCBG’ modes in Tables IV and V, were also a common trend for all of the wind
modes identified in the years 2020 and 2022 cases. This may be seen in the additional wind
plant modes presented in Appendix C.
In order to describe how synchronous generators and CCBG may interact within
interarea and local wind modes, two complementary exercises were executed. In the first one,
the three most dominant synchronous generators of three well known interarea modes in the
2010 case are replaced one by one by full converter wind generators. In the second experiment,
the three most dominant CCBG at two interarea modes and at one wind local mode, are
replaced by synchronous generators. Results presented in Table VI show that the effect of
replacing the synchronous generators by these new wind generators is comparable to the
effect of disconnecting the Power System Stabilizer (PSS) in the original generators.
Also from Table VII, it is seen that the effect of replacing the CCBG by the new
synchronous generators is comparable to disconnecting the original wind generators from the
network. Moreover, the participation factors of the new included synchronous generators in
the original modes are significantly lower than the participation of the original wind generators.
These results revalidate observations from Tables IV and V and from results presented in
Appendices B and C.
12
TABLE VI SYNCHRONOUS GENERATORS REPLACED BY WIND GENERATORS
Interarea Mode1 Most Dominant Synchronous Generators Replaced2
Num f (Hz) ζ (%) Name Areas
Involved One
generator f (Hz) ζ (%)
Two generators
f (Hz) ζ (%) Three
generators f (Hz) ζ (%)
1 0.2262 12.25 PACI (COI)
1. North 54490 0.2342 0.2304 0.2272
14.10 12.36 12.36
54490 59208
0.2365 0.232 0.2275
14.65 12.06 12.06
54490 59208 59908
Singular 0.2339 0.2277
Singular 11.63 11.71
2. South 14913 0.2266 0.2267 0.2262
12.60 12.53 12.32
14913 16518
0.2271 0.2271 0.2266
12.86 12.68 12.32
14913 16518 14945
0.2772 0.2271 0.2266
12.86 12.68 12.34
3 0.749 14.2 Southwest
1. Mexico 20189 0.7745 0.7698 0.7640
11.20 10.88 11.27
20189 20014
0.7821 0.777 0.7698
10.21 9.73
10.34
20189 20014 20010
0.7844 0.7788 0.7709
9.51 9.59
10.19
2. S. Calif, El Paso
26005 0.7534 0.7542 0.7517
13.47 13.43 13.49
26005 26006
0.7549 0.7556 0.7521
13.05 12.99 13.22
26005 26006 11208
0.7530 0.7552 0.7537
14.00 13.96 13.20
4 0.6064 12.6 Kemano
1. East 66439 0.6108 0.6100 0.6058
12.58 12.40 12.46
66439 66437
0.6141 0.6124 0.6064
12.54 12.34 12.34
66439 66437 66438
0.6158 0.6136 0.6067
12.52 12.30 12.24
2. B. C. 50442 0.6096 0.6090 0.6073
12.69 12.66 12.44
50442 50444
0.6114 0.6106 0.6082
12.68 12.62 12.35
50442 50444 50438
0.6125 0.6112 0.6090
12.64 12.60 12.29
1 2010 Base Case original values 2 Synchronous conventional generators with PSS replaced by full converter wind generators (wt4)
Values in blue: No generator. Values in black: Wind generator (without damping controller). Values in orange: synchronous generator (without PSS)
13
TABLE VII WIND GENERATORS REPLACED BY SYNCHRONOUS GENERATORS
Interarea Mode1 Most Dominant Wind Generators Replaced2 Participation
Factors3
Name Case f (Hz) ζ (%) One
generator f (Hz) ζ (%)
Two generators
f (Hz) ζ (%) Three
generators f (Hz) ζ (%) Wt4
Genrou w PSS
Mode 4
2022 0.622 5.92 32342 0.622 0.622
5.85 5.85
32342 32356
0.621 0.621
5.87 5.87
32342 32356 30655
0.621 0.621
5.88 5.88
0.149 0.125 0.124
0.009 0.008 0.009
COI 2020 0.254 19.46 24156 0.256 0.256
19.01 18.91
24156 40687
0.256 0.256
18.77 18.63
24156 40687 50562
0.256 0.255
18.73 18.51
0.58 0.27
0.202
0.003 0.0
0.018
Wind 10
2020 0.36 10.5 40687 0.353 0.353
7.14 7.12
40687 30460
Mode vanishes
1.0 0.479
N.A. N.A.
1 Base Case original values 2 Wind generators (wt4, wt3) replaced by synchronous conventional generators with PSS (genrou, gensal) 3 Participations factors correspond to the three generators in Mode 4 and COI Mode and the two generators in Alberta Mode
Values in blue: No generator. Values in orange: synchronous generator (with PSS).
14
It may be noticed from Table VII, that the wind plant local mode called Wind 10 had a
significant change in its damping ratio when the most dominant wind generator was replaced.
Notice also that, the mode vanishes after the second most dominant wind generator was
replaced. This shows an important characteristic of the sensitivity of the identified wind plant
local modes. Table VIII shows the frequency and damping ratio sensitivities with respect to
selected tuning parameters for the main modes identified in the planned 2022 case. It may be
seen that the CCBG local modes have the highest sensitivities, together with the Kemano mode.
In order to illustrate the difference between sensitivities of interarea electromechanical modes
and wind plant local modes we compared the Kemano and the Wind 12 mode excursions to
variations in selected control parameters.
Table IX and Fig 2 show Kemano mode response with respect to variations in the PSS
gains associated with the most dominant generators in this mode. First, the 70777 PSS gain
value is modified from the default value to a 50% increased value and from the default value to
a 80% reduced value, at different steps. When the speed state variable of generator 50442 was
found to be the most dominant variable, the 50442 PSS gain was taken as the tuning parameter
and this parameter was decreased from its default value to a 95% reduced value. Subsequently,
when the generator 50441 speed variable became the most dominant variable under these
conditions, the generator 50441 PSS gain was decreased from its original value by 20% and 80%
respectively. Table X and Fig. 3 present a similar exercise with the Wind 12 mode, for this case
the tuning parameter was the reactive control gain values of the most dominant wind plants.
These two exercises show that in addition to the high frequency and damping sensitivity of the
wind plant modes, they are highly shaped and can be widely modulated.
Poorly damped modes are also included in Appendix C and they are mostly associated
with small size wind plants. Tuning actions are presented and tested using TSAT for some of the
poor damped 2022 modes involving medium size plants, in order to show suitable corrective
actions.
15
TABLE VIII SENSITIVITIES OF INTERAREA MODES AND WIND PLANT LOCAL MODES FOR THE 2022 CASE
Mode 2022
Num Name f (Hz) ζ (%) Interarea
Index Dominant
State Tuning
Parameter1
Frequency Sensitivity
(%)
Damping Sensitivity
(%)
Wind Participation
Areas
1 PACI (COI)
0.305 19.73 343 / 2044 59111 G1:
Speed
59111 G1 PSS2a:
Ks1 0.00% -0.05% 0 / 73.21
Canada vs. Arizona &
Mexico
2 Alberta 0.47 12.2 527 / 2044 70777 C1:
Speed
70777 C1 IEEEST:
Ks -0.40% 1.56% 0 / 4.39
Alberta vs. B.C. &
Colorado
4 0.622 5.92 65 / 2044 33850 1: Angle
31421 1 IEEEST:
Ks -0.03% -0.17% 0.85 / 30.99
B.C. vs. PG&E
5 Kemano 0.669 13.39 237 / 2044 70777 C1:
Speed
70777 C1 IEEEST:
Ks -0.45% 5.22% 0 / 10.21
B.C. vs. Pace &
PSColorado
6 Colstrip 0.838 9.37 152 / 2044 62025 1: Angle
66439 1 PSS2b:
Ks1 0.10% 0.00% 0 / 31.32 West, NE
11 Wind 11 0.588 6.85 -- 32342 TP:
KVI 32342 TP:
KVI 1.51% 6.41% 4.48 / 4.48
PG&E, Arizona
12 Wind 12 0.607 28.28 -- 24434 T2:
KQI 24434 T2:
KQI 1.52% -2.48% 6.93 / 9.62
SC, S.Diego, Arizona
1 Sensitivities are calculated based on a 10% increase of the tuning parameter
16
TABLE IX KEMANO MODE RESPONSE TO TUNING PARAMETER VARIATIONS
Tuning Parameter
Dominant State
Default Value
Tuning Value f (Hz) ζ (%) Real
part Imaginary
part
Tuning Element
Participation
70777 C1 PSS: K
70777 C1: Speed 1
1.5 (+50%) 0.6539 17.02 -0.7096 4.1085 1 / 12.45
1.1 (+10%) 0.6658 14.10 -0.5957 4.1831 1 / 6.51
1.0 (100%) 0.669 13.39 -0.5695 4.2031 1 / 10.21
0.8 (-20%) 0.6766 12.08 -0.5175 4.2509 1 / 10.19
0.5 (-50%) 0.6924 10.83 -0.4738 4.3505 1 / 13.82
0.3 (-70%) 0.7033 10.9 -0.4845 4.419 1 / 23.97
50442 6: Speed
0.2 (-80%) 0.7074 11.16 -0.4994 4.4444 0.71 / 23.78
50442 6 PSS: Ks1
10
8.0 (-20%) 0.7075 10.93 -0.4891 4.4456 1 / 24.75
5.0 (-50%) 0.708 10.6 -0.474 4.4482 1 / 27.20
50441 5: Speed 2.0 (-80%) 0.709 10.28 -0.46 4.4534 0.97 / 29.61
0.5 (-95%) 0.7094 10.11 -0.4529 4.457 0.93 / 30.40
50441 5 PSS: Ks1
50444 8: Speed 10
8.0 (-20%) 0.71 9.87 -0.4421 4.4586 0.99 / 32.01
31421 1: Speed 2.0 (-80%) 0.712 9.15 -0.4113 4.4739 0.77 / 31.57
17
TABLE X WIND 12 MODE RESPONSE TO TUNING PARAMETER VARIATIONS
Tuning Parameter
Dominant State
Default Value
Tuning Value f (Hz) ζ (%) Real
part Imaginary
part
Tuning Variable
Participation
CCBG Participation
24434 T2: KQI
24434 T2: KQI
0.1
0.1 (100%) 0.6069 28.28 -1.1244 3.8132 1 / 9.62 6.93 / 9.62
0.11 (+10%) 0.6161 27.58 -1.1107 3.871 1 / 6.99 6.36 / 6.99
0.12 (+20%) 0.6246 26.52 -1.0793 3.9244 1 / 6.00 6.00 / 6.00
0.13 (+30%) 0.6315 25.25 -1.0353 3.9681 1 / 5.96 5.96 / 5.96
0.14 (+40%) 0.6364 23.82 -0.9809 3.9986 1 / 6.05 6.05 / 6.05
0.15 (+50%) 0.6383 22.35 -0.9197 4.0107 1 / 6.38 6.38 / 6.38
24411 TP: KQI
0.2 (+100%) 0.6208 19.55 -0.7774 3.9008 0.55 / 7.96 7.96 / 7.96
0.25 (+150%) 0.6122 19.56 -0.7671 3.8463 0.27 / 7.14 7.14 / 7.14
24411 TP: KQI
0.1 0.12 (+20%) 0.6409 17.76 -0.7269 4.0266 1 / 6.7 6.7 / 6.7
0.14 (+40%) 0.6569 14.14 -0.5897 4.1272 1 / 6.05 6.05 / 6.05
24434 TP: KVI
0.2 (+100%) 0.6226 11.48 -0.452 3.912 0.17 / 4.69 4.69 / 4.69
24434 TP: KQI
0.1
0.12 (+20%) 0.6692 5.71 -0.2406 4.2048 1 / 2.64 2.64 / 2.64
0.13 (+30%) 0.6992 2.95 -0.1299 4.3933 1 / 2.54 2.54 / 2.54
0.14 (+40%) 0.7222 0.46 -0.0208 4.5377 0.88 / 2.69 2.69 / 2.69
18
Fig. 2. Kemano mode response to selected control parameters’ variations
Fig. 3. Wind 12 mode response to selected control parameters’
variations
19
Transient Stability Analysis
This transient stability analysis focuses on identifying the Dynamic Critical Contingencies
(DCC) of the transmission system for the planned 2020 and 2022 cases. DCC are defined in this
work as, the contingencies involving a dynamic event with N – 1 or N – 2 type outages that lead
to system instability or to the verge of instability using static and dynamic models. These
contingencies make the system non-compliant with NERC standard categories B [15] and C [16].
When dealing with the dynamic security assessment of bulk power systems, it is
practical to select a set of credible critical contingencies in order to reduce the number of
dynamic simulations and to increase the likelihood of finding critical issues. In this work, two
criteria for identifying dynamic critical contingencies are proposed:
1. Critical contingencies identified in the static security analysis above.
2. Critical contingencies that set the transfer capacity limits to present identified
interarea paths ratings, in terms of stability issues. In this case, the contingencies
are identified from the WECC 2011 Path Rating Catalog [26]. These critical
contingencies may belong to the N – 1 and / or N – 2 category.
Two different types of dynamic events are applied. That is, for events involving N – 1 or
N – 2 AC line outages, a three-phase fault is applied at 4 s at the active power sending bus,
followed by the total clearing of the involved branches. For DC lines or generator units, no fault
is applied, but the component is physically disconnected at 4 s. Notice also that, only circuits
above 100 kV are considered and monitored.
The First criterion for Identifying DCC
The first criterion for identifying DCC includes the dynamic event testing of all previous
SCC identified in the above section for year 2020 and 2022 cases, after corrective actions to
solve the static issues have been applied.
Table XI describes the potential dynamic issues that may be triggered by an event
involving the critical contingencies in criterion 1, for the 2020 base case. Notice that some of
the issues have already been mitigated with the corrective actions taken in the prior static
security analysis. The events involving SCC that did not cause dynamic issues are not included in
Table XI.
Appendix D presents a complete description of the dynamic issues caused by the critical
contingencies identified with the first criterion in the 2020 base case.
20
TABLE XI DYNAMIC RESPONSE TO PREVIOUSLY IDENTIFIED SCC FOR CASE 2020
Area N – 1 Events (Circuit Number) Dynamic Issues
30
30250 30261 (1) Generators at 31782 first swing unstable. Tripped by Over Excitation Limiters (OELs). Small generators at this zone showing negative damped oscillations.
30261 30300 (1)
40
40193 45007 (1)
Wind generator at 40687 showing reactive power low frequency oscillations. Voltage sags at 45348, 45105 and 45184 69 kV buses were prevented
41135 41136 (1) 40537 41135 (1)
Voltage at buses 45216, 45202, 45005 69 kV sags to 68%. Voltage at bus 45348 69 kV sags to 74%. Voltage at buses 45105 115 kV and 45184 69 kV sags to 84%. Wind generator at 40687 showing reactive power low frequency oscillations.
40874 44958 (1)
Wind generator at 40687 showing reactive power low frequency oscillation. Voltage sags at 40237 and 61826 115 kV buses were prevented.
50 50782 50786 (1)
Wind generator at bus 54451 with high reactive power output peak. Wind generator at bus 54165 with reactive power low frequency oscillation. Bus voltage sags and bus frequency oscillations at distribution level were prevented.
54
55164 55165 (57) Generator at bus 55260 with high reactive power output peak. Voltage sag at 55166 69 kV bus was prevented. 55165 55169 (1T)
55229 55234 (49) Generator at bus 55260 with high reactive power output peak. Voltage sags at bus 57234 138 kV and at buses 55235 and 55281 69 kV were prevented.
64
64004 64074 (1) Generator first swing angle instability at 64074 120 kV is prevented. Previous undamped oscillations of nearby generators are now positive damped.
64005 64248 (1) Generators 64074 and 64346 first swing instability and subsequent oscillatory behavior, drag nearby subtransmission system to oscillatory instability including two 1 GVA plants at 26039 and at 26040 buses. 64045 64248 (1)
Pre- disturbance power flows on the cleared lines were below thermal limits.
21
As expected from the selected search criteria, many of the potential security issues are
voltage related violations and some of them are still present in spite of the corrective actions
applied in the static security assessment and presented in Table II. Voltage sags due to an event
involving branch ‘41135 41136 (1)’ or branch ‘40537 41135 (1)’ are shown in Fig. 4.
Fig. 4. Bus voltage dips due to the event including branch ‘41135 41136
(1)’ or branch ‘40537 41135 (1)’
The corrective actions taken in area 64 to reinforce the main outlet circuit from bus
64074 to bus 64045 were sufficient to reduce the severity of an event including branch ‘64004
64074 (1)’, as described in Tables II and XI. The dynamic response after the corrective actions
are applied is presented in Fig. 5.
Fig. 5. Generator rotor angles due to the event including branch ‘64004
64074 (1)’
22
However, the same corrective actions were not sufficient to mitigate the impact of an
event involving critical branches ‘64005 64248 (1)’ or ‘64045 64248 (1)’. The dynamic issues
explained in Table XI are shown in Fig. 6. Additional corrective actions are then necessary in
order to mitigate the effects of some of these dynamic critical contingencies. They are
presented below in Table XII. Notice that for this event, generators 64074 and 64346 first swing
instability is the cause of subsequent growing oscillations of generators at buses 26039, 26040
and 65495.
Fig. 6. Generator active power oscillations due to event including branch
‘64005 64248 (1)’ or branch ‘64045 64248 (1)’
TABLE XII CORRECTIVE ACTIONS TO DCC IDENTIFIED WITH CRITERION 1 FOR CASE 2020
Area Outage Additional Corrective Actions
30 N – 1 Line
30250 30261 (1) Twelve small generators in area 30, with growing rotor oscillations, are tripped. Two shunt capacitors are added in area 30. 30261 30300 (1)
40 N – 1 Line
41135 41136 (1) Three shunt capacitors are inserted in area 40. 40537 41135 (1)
64 N – 1 Line
64005 64248 (1) Two first swing unstable generators at buses 64074 and 64346 are disconnected. 64045 64248 (1)
23
TABLE XIII DCC IDENTIFIED WITH FIRST CRITERION FOR CASE 2022
Area Contingency Name (Circuit Number) Dynamic Issues Corrective Actions
for dynamic issues
40
Line BOARD T2 230.0 to MCNRY S2 230.0 (1) Generator 40344 1 (63.9 MVA) tripped by over excitation limiter (OEL). Generators 44101, 44102, 44103, 44104 (73.7 MVA) and 48061 (66 MVA) with low damped angle oscillations. Generator 45504 (50 MVA) with very slow undamped angle oscillations.
Generators 44101, 44102, 44103 and 44104 PSS compensation changed from leading to lagging. Generator 48061 did not include a PSS. One was added. Generator 45504 exciter parameters tuned to: Trh=20, Te=1.83
Line BOARD T2 230.0 to DR E TP 230.0 (1)
Line DR E TP 230.0 to DALREED 230.0 (1)
Line DR W TP 230.0 to DALREED 230.0 (1)
Line DR W TP 230.0 to JONESCYN 230.0 (1)
Tran LAPINE 230.0 to LAPINE 115.0 (1) Generator 45504 (50 MVA) with very slow undamped angle oscillations.
Generator 45504 exciter parameters tuned: Trh=20, Te=1.83
Line MCNRY S1 230.0 to MCNRY S2 230.0 (1)
Generator 40344 1 (63.9 MVA) tripped by over excitation limiter (OEL). Generators 44101, 44102, 44103, 44104 (73.7 MVA) and 48061 (66 MVA) with low damped angle oscillations.
Generators 44101, 44102, 44103 and 44104 PSS compensation changed from leading to lagging. Generator 48061 does not include a PSS.
65 Line YELOWTLP 230.0 to YELOWBR 230.0 (1)
Big generators 62050 (377 MVA) and 62049 (377 MVA) first swing unstable are tripped. Big generators 62048 (867 MVA), 62047 (867 MVA) with low damped oscillations.
Generators 62048 and 62047 PSS lead compensation tuned to lower frequencies.
24
Table XIII describes the dynamic issues initiated by the DCC identified with the first
criterion for case 2022, including the applied corrective actions. Apart from the first swing
instability issues that triggered the protection schemes, only oscillation problems were found
associated with these contingencies. Figures 7 and 9 illustrate some of the identified oscillatory
problems and Figures 8 and 10 shows the response after corrective actions are applied.
Appendix D includes also a complete description of all simulations results related with
the DCC identified with first criterion for the 2022 case.
Fig. 7. Generator rotor angles due to the event including branch ‘BOARD
T2 230.0 to MCNRY S2 230.0 (1)’
Fig. 8. Generator rotor angles due to the event above, and after PSS’s
tuning
10
15
20
25
30
35
403
.82
4.4
6
5.4
8
6.5
0
7.5
2
8.5
4
9.5
6
10
.58
11
.60
12
.62
13
.65
14
.67
Ro
tor
An
gle
(d
eg
)
Time (sec)
ang___40344
ang___44101
ang___44102
ang___44103
ang___44104
10
15
20
25
30
35
40
3.8
2
4.4
65
.48
6.5
0
7.5
28
.54
9.5
6
10
.58
11
.60
12
.62
13
.65
14
.67
Ro
tor
An
gle
(d
eg
)
Time (sec)
ang___44101b
ang___44102b
ang___44103b
ang___44104b
25
Fig. 9. Generator rotor angles due to the event including branch ‘DR E TP
230.0 to DALREED 230.0 (1)’
Fig. 10. Generator rotor angles due to the event above, and after tuning
action
0
5
10
15
20
25
30
35
3.8
2
4.4
9
5.5
1
6.5
3
7.5
5
8.5
7
9.5
9
10
.61
11
.63
12
.65
13
.67
14
.70
Ro
tor
an
gle
(d
eg
)
Time (sec)
ang___44101
ang___44102
ang___44103
ang___44104
ang___45504
0
5
10
15
20
25
30
35
3.8
2
4.4
9
5.5
1
6.5
3
7.5
5
8.5
7
9.5
9
10
.61
11
.63
12
.65
13
.67
14
.70
Ro
tor
an
gle
(d
eg
)
Time (sec)
ang___44101
ang___44102
ang___44103
ang___44104
ang___45504
26
The Second criterion for identifying DCC
The second criterion for identifying DCC includes the testing of all N – 1 and / or N – 2
events that have been identified in previous operating cases, as the limiting factor due to
stability issues for some of the main Western Interconnection Path Ratings. Table XIV presents
the seven known WECC path ratings with transfer capacity set by stability limits [26] for year
2011. The critical disturbances limiting the transfer capacity for these path ratings are the ones
to be analyzed for the planned 2020 and 2022 cases, according to the second proposed
criterion.
TABLE XIV STABILITY LIMITED PATH RATINGS
Path Transfer (MW) Num Name Actual Limit
4 West of Cascades - North 4,661 10,200 5 West of Cascades - South 3,297 7,200
8 Montana to Northwest 647
(East to West) 2,200
(East to West)
19 Bridger West 1,181
(East to West) 2,200
(East to West)
43 North of San Onofre 2,300
(South to North) 2,440
(South to North) 65 Pacific DC Intertie 2,341 3,100
67 COI 3,093
(North to South) 4,800
(North to South)
It is important to note that power transfers, for the 2020 heavy summer base case and
for the 2022 light spring case, in the selected interarea paths are lower than the established
transfer limits. Therefore, it is expected that even without the modeling of protection and
remedial actions some interfaces remain stable under the applied stability limiting
disturbances. Table XV shows only those event disturbances causing dynamic issues in the 2020
tested case.
As observed from Table XV, there is a wide range of dynamic responses to these
contingencies. However, some contingencies are not critical for this base case since the system
remains stable. In other cases, there are poorly damped oscillations as illustrated in Fig. 11. This
event involves branches ‘24131 24134 (1)’ and ‘24131 24134 (2)’ at Path 43. Also, the
frequencies of the most dominant modes are between 0.8 to 1.0 Hz, with 3% to 5% damping
ratio.
27
TABLE XV DYNAMIC RESPONSE TO EVENTS FROM SECOND CRITERION IN THE 2020 CASE
Path Outage Dynamic Response
4 N – 2 Lines
40957 40869 (1) Gen 62050 first swing unstable. Tripped by Over Excitation Limiter (OEL). The system remains stable. 40957 40381 (1)
5
N – 2 Lines
40585 40699 (1) Poor damped oscillations
40155 40699 (1)
N – 2 Lines
40061 40062 (2) Gen 62050 first swing unstable. Tripped by OEL. The system remains stable. 40155 40699 (1)
8 N – 2 Lines
40459 41057 (1) Gen 62047, 62048, 62050 first swing unstable. Tripped by OEL. Small generators at bus 24815 becoming angle unstable.
40459 41057 (2)
43 N – 2 Lines
24131 24134 (1) Poor damped oscillations
24131 24134 (2)
65 N – 2*
DC Lines PDCI bipole line End Terminals
Small generators in area 30 with growing rotor oscillations
66
N – 2* Units
14932 (1) 14933 (1)
Small generators at bus 24815 becoming angle unstable.
N – 2 Lines
30015 30040 (1) Poor damped oscillations
30015 30030 (1) N – 1*
DC Line PDCI end terminal 2
Small generators in area 30 with growing rotor oscillations
Fig. 11. Generator active power oscillations due to the event at Path 43
0
200
400
600
800
1000
1200
1400
1600
1800
3.9
4.1
4.7
5.3
5.9
6.6
7.2
7.9
8.5
9.2
9.8
10
.4
11
.1
11
.7
Act
ive
Po
we
r O
utp
ut
(MW
)
Time (sec)
20189
22607
24129
24130
28
The action of over excitation limiters, tripping out generators that become unstable at
the first swing, may be effective in some cases to stabilize the system, as described for Paths 4
and 5. However in other cases, these only actions are not sufficient as shown in Fig. 12 for Path
8 where we can observe transient instability in generators connected to bus 24815.
Fig. 12. Generator rotor angles due to the event at Path 8.
Negatively damped local modes are also observed. Losing one or the two poles of the
Pacific DC Intertie (PDCI) bipolar path under the studied conditions resulted in a bunch of small
generators in area 30 having growing rotor oscillations as illustrated in Fig. 13.
Fig. 13. Generator rotor angles due to the event at Path 65.
29
According to the dynamic issues presented in Table XV, basic corrective actions are
taken in order to mitigate the identified DCC and preserve the security of the system. Table XVI
describes simple corrective actions applied to prevent dynamic reliability issues such as voltage
violations, growing angle oscillation and loss of synchronization that puts the security of the
system at risk.
TABLE XVI CORRECTIVE ACTIONS TO DYNAMIC CRITICAL CONTINGENCIES FOR CASE 2020
Path Outage Corrective Actions
8 N – 1 Lines
40459 41057 (1) Seven small generators at bus 24815 are disconnected before losing synchronism. 40459 41057 (2)
65 N – 2
DC Lines PDCI bipolar line End Terminals
Thirteen small generators in area 30, with growing rotor oscillations, are tripped. Two shunt capacitors are added in area 30.
66
N – 2 Units
14932 (1) 14933 (1)
Seven small generators at bus 24815 are disconnected before losing synchronism.
N – 1 DC Line
PDCI end terminal 2 Thirteen small generators in area 30, with growing rotor oscillations, are tripped. Two shunt capacitors are added in area 30.
Next, Table XVII shows the dynamic response of the 2022 case to events identified with
the second criterion. Only those events causing any kind of dynamic issues are included. Here
we had voltage and frequency sag problems due to some of the tested events. Also, first swing
transient instabilities and oscillatory problems are identified. Notice that some of the issues are
corrected as shown in Fig. 17. However some issues like frequency and voltage sags, may
require a detailed study and the implementation of remedial action schemes which are out of
the scope of this work.
Appendix E presents a complete description of the dynamic response of the planned
cases for years 2020 and 2022 to the critical contingencies identified with this second criterion.
30
TABLE XVII DYNAMIC RESPONSE TO EVENTS FROM SECOND CRITERION IN THE 2022 CASE
Path Outage Dynamic Response
4
N-1 Line
Chief Joseph - Monroe 500 kV Gen 62049 and 40344 tripped by Over Excitation Limiters (OEL).
N-2 Lines
Schultz - Raver (1) 500 kV Gen 62049, 62050 and 40344 tripped by Over Excitation Limiters (OEL). Schultz - EchoLake (1) 500 kV
5
N-2 Lines
John Day - Marion 500 kV Gen 62049 and 40344 tripped by Over Excitation Limiters (OEL). Gen 47906 and 47907 terminal voltage is 0.9 pu. Buckley - Marion 500 kV
N-2 Lines
Ashe - Marion 500 kV Gen 62049, 62050 and 40344 tripped by Over Excitation Limiters (OEL). Gen 47906 and 47907 terminal voltage is 0.9 pu. Buckley - Marion 500 kV
8 N-2
Lines
Garrison - Taft (1) 500 kV Gen 62047, 62048, 62049 and 62050 tripped by Over Excitation Limiters (OEL). Frequency in area 62 sags to 59.76. Garrison - Taft (2) 500 kV
65 N-2
Lines PDCI bipole line End Terminals (1 & 2)
Gen 40344 tripped by Over Excitation Limiter (OEL). Gen 47906 and 47907 terminal voltage is 0.9 pu. Gen 44043 and 44044 terminal voltage is 0.93 pu. Gen 44045 terminal voltage is 0.9 pu.
66
N-2 Units
Palo Verde Generators
Stable. Frequency of the entire system sags to around 59.7 Hz steady state value. Especially in areas 54 (Alberta), 50 (British Columbia) and 70 (PS Colorado).
N-2 Lines
Table Mt - Tesla (1) 500 kV Gen 40344 tripped by Over Excitation Limiter (OEL). Wind generator (wt4g) 24155 low damped oscillations.
Table Mt - Vaca Dix 500 kV
N-2 Lines
Malin - Round Mt (1) 500 kV Gen 40344 tripped by Over Excitation Limiter (OEL). Malin - Round Mt (2) 500 kV
31
Fig. 14. Generator rotor angles due to the event at Path 8.
Fig. 15. Bus frequency oscillations due to the event at Path 8.
32
Fig. 16. Generator 24155 poor damped oscillations due to the event at
Path 66.
Fig. 17. After tuning generator 24155 damped oscillations due to the
event at Path 66.
33
IV. ConclusionsThis work presents a systematic and articulated static and dynamic security assessment
for bulk systems applied to the planned Western Interconnection for years 2020 and 2022.
Static and dynamic critical contingencies are identified, as well as some potential security
challenges of the planned system with high penetration of renewable generation are
highlighted.
The proposed approach is a step by step process, articulating a static reliability
assessment and corrective actions following a dynamic reliability assessment. Corrective actions
applied to prevent voltage collapse related to static critical contingencies are shown to be
useful in mitigating some of the voltage issues associated with dynamic events involving these
contingencies. Therefore, the assessment and solution of static risks should precede a dynamic
security assessment.
The dynamic security assessment is then performed over previously identified static
critical contingencies and also on historically stability limited path ratings, reducing in an
effective way the cases of dynamic contingencies to be evaluated to a tractable number.
The retirement of synchronous generators and the deployment of new converter
control based generators have change the mode set in 2020 and 2022 year base cases, with
respect to the 2010 operating case. Some interarea 2010 modes have vanished and some new
interarea modes have emerged. Also, we have seen the appearance of new wind plant local
modes related with converter based control generators.
Direct participation of converter control based generators (without additional power
system damping loop control emulators) over interarea electromechanical modes is negligible.
Likewise, the direct participation of synchronous generators and their controls over wind plant
local modes seems to be insignificant.
Mode frequency and damping ratio sensitivities of converter control based generators
are highly shaped by plant control parameters, especially by the reactive power control loop.
Therefore, we may have local modes of oscillation related to this kind of generators within a
wide variety of oscillation frequencies and damping ratios. In particular, local wind plant modes
with frequencies close to the usual interarea electromechanical mode low frequencies.
According to our results, it seems that modes related with converter control based
plants have only a local nature in spite of their frequency and the geographical distribution of
the generation plants.
34
Potential corrective actions are presented through the analysis with the aim of
proposing likely solutions to the static and dynamic issues described. However, some dynamic
issues may require the implementation of remedial action schemes.
35
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36
[18] GE Positive sequence load flow (PSLF), [Online]. Available:
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37
VI. Appendices
Appendix A: Identified Renewable Generators
Identified renewable generation for years 2020 and 2022 planned cases. Excel files:
• Appendix A (case 2020).xlsx
• Appendix A (case 2022).xlsx
Appendix B: Selected Modes
Detected important modes in years 2010, 2020 and 2022 cases. Excel file:
• Appendix B.xlsx
Appendix C: Selected Additional Modes
Additional selected modes in years 2010, 2020 and 2022 cases. Excel file:
• Appendix C.xlsx
Appendix D: Dynamic Issues from First criterion
Dynamic results from identified static critical contingencies. Excel files:
• Appendix D (case 2020).xlsx
• Appendix D (case 2022).xlsx
Appendix E: Dynamic Issues from Second criterion
Dynamic results from documented stability limited path ratings. Excel files:
• Appendix E (case 2020).xlsx
• Appendix E (case 2022).xlsx
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