Report4 JQ GTH VV April 2013 fv - WECC · 2014-09-12 · ii Summary This is a technical report presented to the Western Electricity Coordinating Council (WECC) as a concluding engineering

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)



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)


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


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


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 (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 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.


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. 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

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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