1. WECC Remedial Action Scheme Reliability Subcommittee
INTERMOUNTAIN POWER PROJECT STABILITY ENHANCEMENT (IPPSE) SYSTEM
Presentation to
WECC Remedial Action Scheme Reliability Subcommittee
April 30, 2010
Ontario Hilton
Ontario, CA

2. INTERMOUNTAIN POWER PROJECT STABILITY ENHANCEMENT (IPPSE) SYSTEM
Presented by:
Ken Silver-Electrical Service Manager (Manager of Energy Control and Extra High Voltage Stations )
Travis Smith-Assistant Manager (Manager of Intermountain Converter Station)
Brian Cast–Electrical Engineer (Grid Operation and Energy Prescheduling Supervisor )
Ken Lindquist – System Protection Engineer
Attendees:
Ken Silver, Mukhlesur Bhuiyan, Travis Smith, Tom Snyder, Brian Cast, Saif Mogri, Ken Lindquist, Carlos Garay and John Hu
Chuck Wu (On Phone)

3. Agenda System Overview – Ken Silver
Performance and Operational History – Travis Smith
System Studies – Ken Lindquist
System Design – Travis Smith
Arming Function – Brian Cast
Operation and Monitoring – Brian Cast
Operating Procedures for Abnormal Conditions - Ken Silver
Commissioning, Maintenance, and Testing – Travis Smith
Conclusions – Travis Smith

4. 1. System Overview

5. 1. System Overview
The Purpose of Intermountain Power Project Stability Enhancement (IPPSE) is to ensure WECC system stability after outages to the Intermountain Power Project DC system (IPPDC). This is achieved by arming predetermined remedial actions prior to the occurrence of a disturbance associated with the IPPDC.
Due to IPPDC system upgrade from 1920MW to 2400MW, the IPPSE is submitted for review.

6. 1. System Overview Remedial Actions Required:
The Intermountain Power Project (IPP) Contingency Arming System (CAS)
has been implemented to mitigate IPPDC disturbances by tripping one or two
IPP generating units. The IPP CAS has been in operation since The
design and operations of this RAS has been reported to WECC on April 1986
with a report entitled “Intermountain Power Project Contingency Arming
System: One Unit Operation” and on August 1992, with a report entitled
“Intermountain Power Project Contingency Arming System: Non-Credibility
of Remedial Action Scheme Failure.”
Formal Operating Procedure:
The IPP CAS consists of arming-charts where real-time power output of the
IPP generating units and the IPPDC line flows are used to select the no-unit,
one-unit or two-unit arming of remedial actions. The IPP CAS and associated
operating procedures are included with the LADWP’s Energy Control Center
Energy Management System (ECC-EMS) computers.

7. 1. System Overview IPP DC Upgrade Project

8. 1. System Overview Intermountain Power Project System

9. 1. System Overview System Map

10. 1. System Overview Intermountain One-line Diagram
One Line Diagram: Adelanto

11. 2. Performance and Operational History

12. 2. Performance and Operational History
The existing IPPSE was installed May 10, 1986
A design criteria of one operational failure in 3 years was used.
How have we done ?

13. 2. Performance and Operational History
In 24 years there have been 28 actions. Seventeen of which occurred prior to August 1992.
There have been 6 failures 5 of which occurred prior to August 1992.
The system did not achieve its goal from 1986 to However from 1992 to the present, the system has achieved its goals.

14. 2. Performance and Operational History
What Changed in 1992?
A problem with the Monopolar Out signal was discovered and corrected.
A design change was initiated to allow for 1 restart in Monopolar Operation.

15. 2. Performance and Operational History
Success
After the modifications, the system operated correctly.

16. 3. System Study

17. 3. Study Process Summary
Co-ordinate with Impacted System Operators (PacifiCorp) in preparing study plan and study conditions.
Determine Impact on the WECC System.
Determine Maximum “IPP Net Import” Capability.
Determine Generation Tripping delay times.
Determine IPP Contingency Arming Scheme (CAS) Operational Nomograms.

18. 3. System Condition Studied IPP DC Upgrade
This is just a simple overview of the IPP STS DC Line and AC connections at Delta, Utah.

19. Stressed TOT2 to Path Rating
3. Utah South Conditions
"Utah South" is most sensitive to the impact of IPP DC. The TOT2B and TOT2C paths were the main focus of this study and stressed to there path rating of 800(TOT2C) and 300(Path2B) throughout this study.
TOT2B
Stressed TOT2 to Path Rating
TOT2C

20. 3. “Net IPP Import” Sensitivity (Post-Transient Power Flow)
Results from the studies reveals that for the loss of IPPDC Bipole, the system is sensitive to the "import", the IPP operation will be limited to 2400MW DC on the STS with import of 600MW (measured at IPP) 
* IPP DC Will Operate with Maximum “Net IPP Import” of 600MW – Limited by Line Overload

21. 3. Determine Delay Generation Tripping
DC Fault Restart
1st
2nd
3rd
Deionization Time (ms)
225
325
425
Deionization Time (cycles)
13.5
19.5
25.5
Cumulative (cycles) 33
58.5
Simulate CAS time (cycles) (trip unit) 18 40 70
Accommodate possible DC restart sequence after a DC fault;
To lessen the stress by possibly using a less stressful turbine or boiler trip.
Generator Tripping
Methods
Time to
0 Output
Comments
Electrical Trip
< 10 Cycles
Most Stressful on boilers
and turbines
Boiler Trip
~ 42 Seconds
15 second Delay
20 seconds to 100MW,
6 second to breaker Open
Turbine Trip
~ 23 Seconds
15 second delay,
2 seconds to 100MW,
6 seconds to breaker Open
This slide shows the timing characteristics of the HVDC controls DC Line Fault Protection.
The studies show that a tripping action needs to occur in the 1st 60 cycles of the event. The 1st line protection restart is accomplished in 18 cycles. However the time to do both the 1st & 2nd, at 40 cycles, is too close to the limit of 60 cycles. Therefore if the 1st restart does not clear the DC Line fault and restore normal power flow a trip signal will be sent.

22. 3. Stability Plot for Loss of Bipole with Restart (for DC Fault Only) (Worst Stressed Condition)
Trip 1 Unit after First Restart Failed and Second Unit after the Second Restart Failed
Trip Both Units after First Restart Failed
Here we see the study results showing that if we wait for the second DC Line Protection action the AC Voltage dip exceeds the criteria.
* CAS Will Trip Units after 1 Restart Attempt Failed

23. 3. Stability Plot for Loss of Bipole with Delayed CAS Generation Tripping for Lower IPP DC Schedule
IPP DC Schedule 1500MW
IPP DC Schedule 1400MW
Here we show that when the total DC power transmitted is at or less than 1400 MW stability is not an issue. There is more time to allow a ‘softer’ trip of the generators. This a turbine or boiler trip depending on arming.
The charts show that there is more time before a trip needs to occur and the system swing is less.
* CAS Will Delay Generation Tripping for IPP DC Schedule 1400MW or Less

24. 3. Delayed CAS Generation Tripping for Loss of 1 Pole
Short Term Overload Capability of IPP DC
Loss of Bipole is only possible for simultaneous DC faults or disastrous DC Controls failure.
AC faults will result in the loss of 1 pole. This chart is here to show the overload capability of the STS HVDC. If there is a loss of one pole when operating in Bipolar mode there is an automatic increase of power on the remaining pole up to 1600MW DC. Then both the IPP generation and HVDC ramp down to the maximum pole rating, 1200MW, over a controlled 7 minute ramp. This feature helps to minimize the shock to the AC network.

25. 3. Delayed CAS Generation Tripping for Loss of 1 Pole (IPP AC Fault Trip 1 Unit + MWC Generations)
No RAS
Delayed Tripping
Fast Tripping
Here we are looking at the effects of the STS HVDC in Bipolar operation and the event is losing one of the poles.
1st chart shows that stability is not an issue.
2nd chart shows that allowing a boiler or turbine trip, a delayed trip, there is less impact to the AC system.
3rd chart shows that an electrical trip results in larger swings that the remaining generator is exposed to.
* CAS Will Delay Generation Tripping for Loss of 1 Pole

26. 3. IPP CAS Generation Tripping Level Operating Nomogram for Bipole Operation for the Loss of Bipole
Chart on the left, each dot represents a separate case that was run.
The limitation found is the post-transient current flow at the Sigurd-Three Peaks location.
The right hand chart is the nomogram developed from the study results.

27. 3. IPP CAS Generation Tripping Level Operating Nomogram for Bipole Operation for the Loss of 1 Pole
For Bipole operation and the loss of one pole the limitation is the post-transient voltage deviation at Abajo 69KV bus.
Nomogram developed from the studies is again on the right.

28. 3. IPP CAS Generation Tripping Level Operating Nomogram for Mono-pole Operation for the Loss of 1 Pole
(Just in case people ask about restrictive nomogram for mono-polar operation. Voltage deviation N-1 criteria is 5% while N-2 is 10%. )
The other normal operating mode for the STS HVDC is to have only one pole in operation.
Here the limitation is the post-transient current flow at Sigurd-Three Peaks
AND the voltage deviation of 5% at Abajo. And the nomogram to the right.
This concludes the studies presentation.

29. 3. Study Summary
IPP DC limited to net AC Import capability of 600MW under maximum Utah South export conditions
CAS will Trip Units after 1 Restart Attempt Failed
CAS will Delay Generation Tripping for IPP DC Schedule 1400MW or Less
CAS will Delay Generation Tripping for Loss of 1 Pole - Limited by Voltage Deviations
In summary:
The thermal line overload is when 2400MW with 600 MW of import.
Action will be initiated if the 1st line protection restart is not successful.
When the STS is operating at or below 1400MW a delayed trip is allowed.
The loss of one pole with a delayed trip also meets all criteria.

30. 4. System Design

31. 4. System Design
Design Philosophy
Meet the System Studies Guidelines
Insure Redundancy
Reduce the Hardware
Centralize the Logic

32. Only 1 operational failure in 3 years is allowed.
4. System Design
Following the guidelines established by the system studies were the driving force in the design of the IPPSE.
All parameters of the studies have been met which also allowed for a simpler more efficient design.
Only 1 operational failure in 3 years is allowed.

33. 4. System Design

34. 4. System Design
The Bipole Controls are a completely redundant Mach 2 Control System designed by ABB.
All protection actions are routed through this control system.
The IPPSE Logic is fully contained in this system thus reducing the system hardware requirements.
All remedial outputs are generated from this control system.

35. 4. System Design
The remedials from the IPPSE Logic have been simplified into two outputs.
Monopolar Out
Bipolar Out
Based on these two signals and the Nomograms, all IPPSE actions are appropriately taken.

36. Generator Trip Remedials
4. System Design
Generator Trip Remedials
Electrical Trip (86 Lockout)
Turbine Trip
Boiler Trip

37. IPP Digital Microwave System
4. System Design
IPP Digital Microwave System
Original analog system installed 1985
System was replaced with Harris Stratex (now Aviat Networks) digital microwave radios in 2004
LADWP operated and maintained

38. IPP Microwave Power Redundancy
4. System Design
IPP Microwave Power Redundancy
Propane Back up Generators
24 VDC Power Plants

39. 4. System Design
IPP Microwave One Line

40. 5. Arming Function

41. 5. Arming Function Overview:
Arming is automated by an application running in LADWP’s energy management system.
Nomograms, called “charts”, specify the arming level.
Each chart has a series of curves that provide arming levels as a function of IPP net generation (including Milford generation) and the DC line flow.
The application selects charts based on monitored power system conditions and the specific trigger being armed.

42. 5. Arming Function Charts: One curve per remedial action.
Arming is a function of net gen vs. DC flow.
Top-most curve provides DC flow limit.
Added remedial actions will require an increase in the number of curves per chart.

43. 5. Arming Function Chart Sets:
There may be up to five triggers for remedial actions.
Each trigger has its own arming for remedial action.
Therefore, there is one chart per trigger.
The set of charts for the triggers is a “chart set”.

44. 5. Arming Function Chart Set Selection:
There are multiple chart sets to accommodate varying system conditions.
Chart sets are functionally organized into rows and columns.
Columns are selected based on monitored line flows.
Rows are selected based on line outages and IPP operating modes.

45. 5. Arming Function Chart Set Selection (cont’d):
Original design provided for 24 columns.
Although they no longer affect arming, three power flows are still monitored: Pacific AC Intertie, Arizona–California, and Utah South.
The system study indicates nomogram sensitivity to Utah South power flow, so use of multiple columns may become necessary.

46. 5. Arming Function Imports: Chart shows a 600-MW import limit.
IPP AC lines have 1317-MW import capability.
Chart is worst-case scenario.
Other cases allow more imports.

47. 5. Arming Function Import Example:
A 72-MW  on Sigurd–Three Peak may allow a 400-MW  in imports.
This can be implemented via multiple columns or via dynamic shifting of affected curves.

48. 5. Arming Function Summary of Arming Function Changes:
Increase in the number of curves per chart due to increase in number of remedial actions.
Decrease in the number of charts per chart set due to decrease in the number of triggers.
Increase in the number of chart set columns and/or addition of dynamic curve adjustments due to varying AC import limits depending on Utah South flow.

49. 6. Monitoring and Operation

50. 6. Monitoring and Operation
Overview:
LADWP’s Energy Control Center (ECC) and IPP both have monitoring capability.
The arming application runs at the ECC, but either site can arm manually.
Except for automatic arming, the RAS operation occurs entirely at IPP, but is monitored by both sites.
The slides that follow show monitoring and operation as seen at the ECC.

51. 6. Monitoring and Operation
The interface at the ECC includes the following displays:
Curves & DC Limits
Columns & Charts
Panel Status (i.e. RAS Status)
Annunciators
These displays are summarized and shown in the slides that follow.

52. 6. Monitoring and Operation
Curves & DC Limits:
Shows summary data in upper-right corner.
Provides for viewing and update of curves and charts.
Shows remedial action selected for each active chart.
Shows DC limits from charts and other nomograms.

53. 6. Monitoring and Operation
Curves & DC Limits Display

54. 6. Monitoring and Operation
Changes to Curves & DC Limits:
System studies do not show a need for separate nomograms for DC limits from Utah North, Utah South, or Northeast/Southeast flows.
DC limit for power flows flow will be inherent in the contingency arming limit from the selected charts.
Dynamic offsets to curve data, when implemented, will be shown on this display.

55. 6. Monitoring and Operation
Columns & Charts:
Shows power flows for chart set column selection.
Shows line status.
Shows plant operating mode.
Shows column and chart set selection in the summary data in the upper-right corner.

56. 6. Monitoring and Operation
Columns & Charts Display

57. 6. Monitoring and Operation
Changes to Columns & DC Charts:
Column selection is no longer influenced by Pacific AC Intertie and Arizona–California flows.
Additional columns may be needed to model the effects of Utah South flow on AC import capability.

58. 6. Monitoring and Operation
Panel Status:
The RAS is currently implemented at IPP via redundant hardware systems called “panels”.
Each arming control point is wired to operate both panels from a single control operation.
Each panel independently reports its status.
Arming controls can be issued via the arming application or manually via SCADA control actions.

59. 6. Monitoring and Operation
Panel Status (cont’d):
Provides a control and pair of state indications for each combination of trigger and remedial action that may be armed.
Provides for manual entry of an arming pattern when in MANUAL mode and shows the application-determined arming pattern when in AUTOMATIC mode.
Shows panel status values.
Shows triggers actuated. When a trigger is actuated, the RAS will execute any remedial actions armed for that trigger.

60. 6. Monitoring and Operation
Panel Status Display

61. 6. Monitoring and Operation
Changes to Panel Status:
The application currently implements the arming matrix by using an obscure feature to control multiple arming state points with a single control operation. (This is much quicker than using time-consuming discrete control actions for each arming state point.)
This set of arming state points to specify remedial actions for each trigger will be replaced with a single analog point for each trigger that specifies the remedial actions to execute.
The RAS implementation will be part of the DC control system.

62. 6. Monitoring and Operation
Annunciator Displays:
The RAS trigger inputs are actually aggregations of multiple triggering inputs from relay and DC control systems.
For this reason, the RAS trigger inputs are in some places called “super triggers”.
The annunciator displays show each trigger input and identify the super triggers that it activates.

63. 6. Monitoring and Operation
Annunciator Display 1

64. 6. Monitoring and Operation
Annunciator Display 2

65. 6. Monitoring and Operation
Annunciator Changes:
According to system studies, many of the triggering inputs will no longer require remedial actions.
Only triggering inputs for monopole and bipole blocks will continue to be relevant.
The number of super triggers needed will reduce from five to two.
The triggering inputs no longer requiring remedial action may be retained on the annunciator displays for reference.

66. 6. Monitoring and Operation
Summary of Monitoring and Operation Changes:
The RAS function will be located in the DC control system.
Arming will be specified via analog arming levels rather than discrete digital states.
Arming may use real-time power flow to bias affected nomogram curves.
Additional remedial actions are being added.
The inputs that affect remedial action arming and execution are being updated according to study results.

67. 7. Operating Procedure for
Abnormal System
Conditions

68. 7. Operating Procedures for Abnormal System Conditions
The RAS operates incorrectly (failure to operate or false operation)
As soon as the IPPSE has failed or operated improperly, generation and DC flows will be curtailed to a point where remedial action is not required. The condition will be maintained until repairs can be made or the RAS is proven to be stable.

69. 7. Operating Procedures for Abnormal System Conditions
One part of a redundant RAS system is unavailable so that complete redundancy is no longer assured
Personnel will be dispatched immediately to work on the unavailable system to restore it to operational status as soon as possible. Curtailment is not required in this condition.

70. 7. Operating Procedures for Abnormal System Conditions
When unscheduled, or unplanned and not coordinated, unavailability of the subject RAS (complete loss of RAS) impacts operation
Generation and DC flows will be curtailed to a point where RAS is not required or until such time as the RAS becomes available again.

71. 7. Operating Procedures for Abnormal System Conditions
When a partial or total loss of input data required for arming decisions
All input data required for arming originates from Intermountain Converter Station (ICS) and Intermountain Generating Station (IGS). The ICS operator will manually set the proper arming as directed by the Energy Control Center (ECC). The ICS operator has the ability to determine and set proper arming independent of ECC.

72. 8. Commissioning, Maintenance and Testing

73. 8. Commissioning, Maintenance, and Testing
Testing of the IPPSE Logic will begin during the Factory Acceptance Tests in Sweden. This will begin in May 2010.
Commissioning of the new system will begin in October of 2010 when the first Mach 2 control comes on line.
The IPPSE system will be fully operational by Mid December 2010.

74. 8. Commissioning, Maintenance, and Testing
All critical components such as communication links, test switches and computers are monitored by the new Alarm Reporting and Monitoring System (ARMS)
Emergency maintenance can be done on line without degrading the system. Only redundancy will be lost.
Scheduled Maintenance is every 2 years.

75. 8. Commissioning, Maintenance, and Testing
Testing will be “End to End”, from ECC to the Generator and Milford Intermountain Line 1 Blocking Switches.
Each arming level in the Nomograms will be tested to assure that the proper remedial is sent to the blocking switch.
All intermediate signals, remedial outputs and trip signals will be recorded for analysis.

76. 9. Conclusions

77. System Studies Guidelines
9. Conclusions
System Studies Guidelines
System studies were extensive and the results were incorporated into the system design.
All system hardware and software is monitored for correct operation.

78. Redundancy 9. Conclusions
All Protections, Control Systems, Communication Systems and Monitoring Systems are completely redundant.

79. Reduce and Simplify the Hardware
9. Conclusions
Reduce and Simplify the Hardware
The input triggers have been reduced from 19 to 2.
The Nomograms have been reduced from 38 to 3.

80. Centralize the Logic 9. Conclusions
All IPPSE Logic is now contained in the HVDC Mach 2 control system.

81. Questions?