1. 2009 West-North Stability Limit Study Reliability Assessment Group ERCOT System Planning Phase II –Effects of Adding PSS on System Limits Regional Planning Group Meeting, Jan 2010

2. 2 Regional Planning Group MeetingJan 2010 Outline Study Objectives and Assumptions Introduction  What is the West-North Stability Limit and how is it calculated?  System Oscillation – how is it related to stability limits?  How to improve system response to oscillations? Power System Stabilizers (PSS)  Will this improvement increase the system transfer limits on the West-North interface? Study Results and Observations Discussion

3. 3 Regional Planning Group MeetingJan 2010 Study Objectives and Assumptions Objective –  Determine the effect of adding Power System Stabilizers (PSSs), on the system stability limits. Limiting conditions for the PSS to affect machine damping –  PSS will be effective only when the unit is online, and  The voltage regulator (AVR) at the unit must be ‘on’. Study Assumptions & Limitations –  The base-case and dynamic data sets are the same as those used to calculate 2009-2010 W_N Transfer Stability Limit (http://www.ercot.com/gridinfo/congestion/) 2009-2010 W_N Transfer Stability Limithttp://www.ercot.com/gridinfo/congestion/  Permian Basin and Morgan Creek CTs: It is assumed that only one of these two sets of units is available for dispatch. The case of both sets of units being simultaneously online has a low frequency of occurrence (< 3%, based on 2008 dispatch data from the PI database) and is not considered in this study.  West Texas Wind: Wind units are modeled with no dynamic response.  Load Modeling: Standard ZIP load models prepared by DWG are applied.

4. 4 Regional Planning Group MeetingJan 2010 The West-North Stability Limit The 2009 West-North Stability Limit study identifies six 345kV transmission lines from the West-North interface to be monitored for power transfer. When the flow along this interface exceeds a set limit (dependent on the operating conditions), the system would experience low-frequency oscillations in the event of contingency, due to generators in one region swinging against generators in another region. This limit is defined as the West-North transfer stability limit. The six 345kv transmission lines monitored to maintain the WN transfer stability limit are –Long Creek to Graham –Cook Field To Graham –Tonkawa to Graham –Bowman to Graham –Bowman to Jacksboro –Red Creek to Comanche WN transfer stability limit is decided based on the combination of –Line outage –Unit outage –Contingency

5. 5 Regional Planning Group MeetingJan 2010 System Oscillations When perturbed from steady-state operation by fault/contingency, system shows an initial transient response. Assuming there is no angular separation, the system then attempts to settle around a new operating point. If in the post-transient operation, a natural mechanical mode of the system is poorly damped, then low frequency local or inter-area oscillations in the range of 0.2 – 2 Hz appear. These system oscillations and their associated damping, form the small- signal stability response of the network.  All limits in this study were determined either by angular instability (separation) or by the low-frequency oscillation damping ratio. –If post-transient, one or more machines show angular separation then the system is assumed to be operating beyond limits. –If post-transient, the small-signal damping ratio is less than 3.5%, the transfer is assumed to be beyond limit.

6. 6 Regional Planning Group MeetingJan 2010 System Oscillations – Damping Coefficient Power system oscillations are characterized by Eigen-values and corresponding Eigen-vectors. Least Square Error Analysis was the method used for Eigen value evaluation. –A summation of exponential and damped (or un-damped) sinusoidal terms is used to generate a least-square error fit of the system response. Each exponential component is associated with one attenuation constant σ i. Similarly, each sinusoidal term is associated with an attenuation constant and mode frequency component σ j and ω j, respectively. If the Eigen-value is σ + jω, then the damping ratio is defined as  The limiting damping for transfer limits is 3.5% on the dominant mode.

7. 7 Regional Planning Group MeetingJan 2010 System Oscillations – Damping and Instability (a) Angular Instability first-swing (d) Well Damped (b) Angular Instability Negative Damping (c) Under Damped

8. 8 Regional Planning Group MeetingJan 2010 System Oscillations – Modes of Oscillation  REFERENCES – 1.V. Larsen and D. A. Swann, “Applying Power System Stabilizers Part II: Performance Objectives and Tuning Concepts”, IEEE Trans. On Power Apparatus and Systems, Vol. 100, 1981, pp 3025-3033 Types of System Modes of Oscillation –Inter-area or Inter-Tie Modes The aggregate of units at one end of an inter-area tie oscillating against the aggregate of units at the other end. –Local Modes Oscillations occurring at generating units connected to large power system through weak (mostly radial) transmission lines.

9. 9 Regional Planning Group MeetingJan 2010 Power System Stabilizers  REFERENCES – 1.V. Larsen and D. A. Swann, “Applying Power System Stabilizers”, IEEE Trans. On Power Apparatus and Systems, Vol. 100, 1981, pp 3017-3046 Power System Stabilizer (PSS): –A device used to damp low-frequency oscillations by modulating generator excitation and as a consequence, extending power transfers limited by these oscillations. A PSS uses shaft speed, AC bus frequency and/or electrical power as input signals.  NOTE: The PSS is a device that can efficiently improve system damping ratio for local and inter-area oscillatory modes. Other means are used to control/check first-swing transient instability.

10. 10 Regional Planning Group MeetingJan 2010 Power System Stabilizers – Operating considerations  REFERENCES – 1.V. Larsen and D. A. Swann, “Applying Power System Stabilizers Part II: Performance Objectives and Tuning Concepts”, IEEE Trans. On Power Apparatus and Systems, Vol. 100, 1981, pp 3025-3033 It is not unusual for a generating unit to participate in both local and inter- area modes of oscillation. Power system stabilizers must therefore be able to accommodate both modes. –Since a single unit or small set of units is dominant in local modes, the PSSs can have a very large impact on damping the oscillation. –In an inter-area mode a single unit experiences only a portion of the total magnitude of power oscillation. The PSS’s contribution to the damping of an inter-area mode is dependent on the extent of participation of the unit in that mode. A PSS should be designed to provide adequate local and inter- area mode damping under all operating conditions, with particular attention to conditions of heavy load and weak transmission.

11. 11 Regional Planning Group MeetingJan 2010 PSS – Assumptions and Limitations of the Study Study performed for three conditions applied to every unit and line outage scenario – –Morgan Creek CTs Offline –Permian Basin CTs Offline –Both sets of CTs Offline At least one of the units where additional PSS were placed was online in every scenario examined –Any PSS will only have an effect on system oscillations when the unit it is connected to is online and the unit’s AVR is on. This study assumes that all existing stabilizers are already tuned to deal with local and inter-area oscillatory modes.

12. 12 Regional Planning Group MeetingJan 2010 Effect of adding PSS – Choice of Units The units from the West CSC zone were chosen to study the effects of adding PSS on the system stability limits because clearly, they have the most positive impact on system oscillations. Unit Bus #Unit NameParticipation Unit Type Zone 1002Permian Basin CT11CTWest 1003Permian Basin CT21CTWest 1004Permian Basin CT31CTWest 1005Permian Basin CT41CTWest 1006Permian Basin CT51CTWest 1007Permian Basin Unit51RMRWest 1039Morgan Creek CT11CTWest 1040Morgan Creek CT21CTWest 1041Morgan Creek CT31CTWest 1042Morgan Creek CT41CTWest 1043Morgan Creek CT51CTWest 1044Morgan Creek CT61CTWest 1045Cal Energy Unit11Co-GenWest 1046Cal Energy Unit21Co-GenWest 1047Cal Energy Unit31Co-GenWest 1069Kinder Morgan0.917CC, SSWest 1320Big Spring Carbon Plant 10.917Co-Gen, SSWest 1479Wichita Falls0.17CCWest 1482Wichita Falls0.17CCWest 1433Graham0.14Base Load NGWest Units with highest participation in System Oscillations Plot of the effect of various combinations of PSS  Highlighted units not chosen –  Permian Basin Unit 5 is RMR and likely to be phased out of operation.  Units at Kinder Morgan, Big Spring, Wichita Falls and Graham are too small.

13. 13 Regional Planning Group MeetingJan 2010 Effect of adding PSS – Choice of Units (contd.) Limiting assumptions:  The tuning of existing PSS as a means of improving stability limits was not considered. Existing PSS models should be validated and tuned for the 0.2 to 2 Hz range to cover both inter-area and local modes of oscillation. It is assumed that all existing stabilizers are already tuned to deal with these modes.  The new PSS models added in this study utilize parameters of the most common PSSs in the model database and do not eliminate the need for tuning of the PSS upon installation.  Units chosen as candidates for addition of PSS – Permian Basin CTs Morgan Creek CTs Cal Energy Gas Turbine Units (From DYRE 77) Primary Mode Damping for several combinations of PSS DYREAdditional Unit with PSS Damping (%) Primary mode = 0.774Hz 77PB CTs, MC CTs & Cal Energy (1 & 2)7.12 75PB CTs, MC CTs & Cal Energy6.65 66PB CT 1 & Monticello 13.7 49PB CT 23.61 50PB CT 33.58 52PB CT 53.58 44PB CT 13.58 51PB CT 43.56 25PB unit 5 & Monticello 13.52 0None1.37

14. 14 Regional Planning Group MeetingJan 2010 Effect of adding PSS – Improvement in Damping Unit Outage System Damping Improvement (For the Limiting case without PSS) No Additional PSSPSS - DYRE 77 273.4112.68 363.2612.5 353.049.71 262.29.02 293.388.6 283.128.34 32Unstable8.23 243.498.06 83.38 93.148 342.737.86 333.417.78 113.187.69 252.357.65 302.787.54 202.177.5 7Unstable7.49 310.57.48 52.817.13 193.267.08 173.197 182.337 32.416.81 41.956.76 12.446.64 211.066.5 22.036.47 22Unstable6.18 101.325.98 122.085.93 14-0.385.73 13-0.645.71 6Unstable5.6 15Unstable4.29 16Unstable 23Unstable

15. 15 Regional Planning Group MeetingJan 2010 Effect of adding PSS – Improvement in Transfer Limits Unit OutageTransfer with No Additional PSSΔtransfer with PSS 91161419 84901127 364341122 279651054 2611741003 1875993 35619954 17282867 31090342 11378325 12555305 29869303 14718291 211654277 241923276 251638276 2910267 41074255 1772248 201406242 191283216 301122199 51282197 341232190 28704175 13554154 71325149 61475148 151007148 10250147 221642137 321322132 311067110 33157316 2319330 168560 Stability Limits for Line Outage L13

16. 16 Regional Planning Group MeetingJan 2010 Observations Addition of PSS drastically improved system damping – consequently, system small-signal stability limit also saw a dramatic increase. The PSS is the device most commonly used to improve the system damping ratio for low frequency local and inter-area oscillatory modes. There were several cases where transient instability from negative damping changed to a well- damped response after stabilizers were added.

17. 17 Regional Planning Group MeetingJan 2010 Study Conclusions With additional power system stabilizers on the West Texas Permian Basin CTs, Morgan Creek CTs, and Cal Energy gas turbine units the West-North Stability Limits are found to increase under all study conditions (all of which have one or more of these units online) with few exceptions. There is no change in the Limits when these units are not online. The Permian Basin CTs or Morgan Creek CTs are peaking units rarely deployed. The best units for addition of PSS would be at Cal Energy. When either PB or MC CTs are removed from the dispatch, the West-North Stability Limits would increase due to much lower small-signal oscillations. The highest small-signal stability limits are determined when the Permian Basin CTs as well as Permian Basin unit 5 (RMR) are not included in the system dispatch. Separate analysis is underway to determine how frequently these units are online when the Stability Limits are binding.

18. 18 Regional Planning Group MeetingJan 2010