GADS Data Reporting Workshop GADS Data Reporting Workshops May, August & October, 2017

Transcription

1 GADS Data Reporting Workshop 2017 GADS Data Reporting Workshops May, August & October, 2017

2 Introduction and Overview 2017 GADS Data Reporting Workshops Module 01 October, 2017

3 Primary Instructors Introduction of Facilitators Leeth DePriest Southern Company Services and Chairman GADS Working Group Mike Curley Navigant Consulting (MicroGADS Product Manager), GADSWG Observer and former NERC GADS Services Manager Introduction of Attendees Your name Company GADS experience 3 RELIABILITY ACCOUNTABILITY

4 Welcome NERC Performance Analysis Staff Donna Pratt Performance Analysis Manager, Data Analytics Margaret Pate Liaison, Reliability Risk Analysis and Control Lee Thaubald Technical Analyst David Till Senior Manager 4 RELIABILITY ACCOUNTABILITY

5 What is NERC? What is GADS? Why mandatory GADS? What units are required? Data Input Needed IEEE 762 Equations and their meanings (Metrics) What are the equations calculated by GADS? What are they trying to tell you? Review of standard terms and equations used by the electric industry. Agenda 5 RELIABILITY ACCOUNTABILITY

6 Questions? 6 RELIABILITY ACCOUNTABILITY

7 History of NERC and GADS 2017 GADS Data Reporting Workshops Module 02 October, 2017

8 What is NERC? November 9,1965 Northeast black out 30 million people affected $100 million of economic losses 1967 Federal Power Commission investigation. Recommends council on power coordination Regional groups formed NERC 8 RELIABILITY ACCOUNTABILITY

9 NERC Regional Entities (RE) Florida Reliability Coordinating Council Midwest Reliability Organization Northeast Power Coordinating Council ReliabilityFirst Corporation SERC Reliability Corporation Southwest Power Pool, Reliability Entity Texas Regional Entity Western Electricity Coordinating Council 9 RELIABILITY ACCOUNTABILITY

10 What is GADS? G - Generating A - Availability D -Data S -System 10 RELIABILITY ACCOUNTABILITY

11 The GADS Databases Design equipment descriptions such as manufacturers, number of BFP, steam turbine MW rating, etc. Performance summaries of generation produced, fuels units, start ups, etc. Event description of equipment failures such as when the event started/ended, type of outage (forced, maintenance, planned), etc. 11 RELIABILITY ACCOUNTABILITY

12 Unit Availability Database GADS maintains a history of actual generation, potential generation and equipment outages. Not interested in dispatch requirements or needs by the system! ** If the unit is not available to produce 100% load, we want to know why! 12 RELIABILITY ACCOUNTABILITY

13 GADS became mandatory in RELIABILITY ACCOUNTABILITY

14 Mandatory GADS MW Sizes and When Generator Owners shall report their GADS data to NERC as outlined in the GADS Data Reporting Instructions (Appendix III) for design, event and performance data for generating unit types listed above for units 50 MW and larger started January 1, 2012 and 20 MW and larger started January 1, 2013 Generator Owners not listed on NERC s Compliance Registry may report to GADS on a voluntary basis. All small MW units invited but are voluntary. 14 RELIABILITY ACCOUNTABILITY

15 What are Conventional Generating Units? The ten types of conventional generating units: Fossil steam including fluidized bed design; Nuclear; Gas turbines/jet engines (simple cycle and others modes); Internal combustion engines (diesel engines); Hydro units/pumped storage; Combined cycle blocks and their related components (gas turbines and steam turbines); Cogeneration blocks and their related components (gas turbines and steam turbines); Multi boiler/multi turbine units; Geothermal units; and Other miscellaneous conventional generating units (such as variable fuel biomass, landfill gases, etc) used to generate electric power for the grid and similar in design and operation as the units shown above and as defined by the GADS Data Reporting Instructions. 15 RELIABILITY ACCOUNTABILITY

16 Recommendations In-house Audits In house review of GADS data by the reporting generating company has always been strongly encouraged. Each reporting generating company shall continue to be responsible for collecting, monitoring, updating and correcting their own GADS design, event, and performance data. 16 RELIABILITY ACCOUNTABILITY

17 Recommendations Ownership/Retirement NERC shall track ownership changes as generating units are sold to other operating companies. These changes will include the name of the new owners and the date of generating unit transfer. (Please note that GADS has been collecting ownership transfers for 10 years with no burden on reporters.) Proposed or projected generating units retirement dates shall not be collected in GADS 17 RELIABILITY ACCOUNTABILITY

18 Questions? 18 RELIABILITY ACCOUNTABILITY

19 Design Data & Fundamentals 2017 GADS Data Reporting Workshops Module 03 October, 2017

20 The GADS Data Monster 20 RELIABILITY ACCOUNTABILITY

21 Why Collect Design Data? For use in identifying the type of unit (fossil, nuclear, gas turbine, etc). Allows selection of design characteristics necessary for analyzing event and performance data. Provides the opportunity to critique past and present fuels, improvements in design, manufacturers, etc. Design data is essential for many generating plant analyses. Generating companies will be asked to review and update their design data annually or as recommended by NERC staff using the design timestamping process, but the updating will be voluntary. 21 RELIABILITY ACCOUNTABILITY

22 Unit Types (Appendix C) Unit Type Fossil (Steam) (use if additional numbers are needed) Coding Series Nuclear Combustion Turbines (Use if additional numbers are needed) Diesel Engines Hydro/Pumped Storage (Use if additional numbers are needed) Fluidized Bed Combustion Miscellaneous (Multi-Boiler/Multi-Turbine, Geothermal, Combined Cycle Block, etc.) RELIABILITY ACCOUNTABILITY

23 Recommendations - Design The nine design data fields were chosen for two specific reasons: Allowing GADS data to be matched with information collected in the Transmission Availability Data System (TADS). One goal of NERC is to allow the GADS and TADS databases to interact with each other. Certain data fields are needed to allow generating units to be located in areas where transmission lines are located. Specific fields allow that interaction. Editing the event and performance data to insure the continued quality of information collected by GADS. 23 RELIABILITY ACCOUNTABILITY

24 Required Design Data GADS utility code (assigned by GADS Services) GADS unit code (assigned by the reporting company following the guidelines in Appendix C of the GADS Data Reporting Instructions.) NERC Regional entity where the unit is located Name of the unit Commercial operating date Type of generating unit (fossil, combined cycle, etc.) MW size (nameplate) State or province location of the unit. Energy Information Administration (EIA) Plant number (US units only). 24 RELIABILITY ACCOUNTABILITY

25 Treat as Normal Unit. Multi-units on Meters 10 MW 10 MW 10 MW 10 MW 10 MW Meter Meter Meter Meter Meter If sum over 20 MW, then reportable to GADS Treat as Miscellaneous Unit 10 MW 10 MW 10 MW 10 MW 10 MW Meter 25 RELIABILITY ACCOUNTABILITY

26 Design Updating? Is additional design needed to analyze the GADS data? Gas turbine manufacturer? Steam turbine details? Boiler design (subcritical vs. supercritical)? Time stamping? 26 RELIABILITY ACCOUNTABILITY

27 Design Data Forms are Voluntary! Forms are located in Appendix E are all voluntary reporting! Complete forms when: Utility begins participating in GADS Unit starts commercial operation Unit s design parameters change such as a new FGD system, replace the boiler, etc. 27 RELIABILITY ACCOUNTABILITY

28 Questions? 28 RELIABILITY ACCOUNTABILITY

29 Outage Event Reporting 2017 GADS Data Reporting Workshops Module 04 October, 2017

30 Why Collect Event Records? Track problems at your plant for your use. Track problems at your plant for others use. Provide proof of unit outages (ISO, PUC, consumers groups, etc). Provide histories of equipment for lessons learned. Provide planning with data for determining length and depth of next/future outages. 30 RELIABILITY ACCOUNTABILITY

31 Event Identification Utility (Company) Code a three character alpha numeric code that identifies the reporting organization. Assigned by OATI for NERC (required) Unit Code a three digit code that identifies the unit being reported. This code also distinguishes one unit from another in your utility (required) The combination of the utility and unit codes uniquely identifies your units! 31 RELIABILITY ACCOUNTABILITY

32 Event Identification (cont.) Year the year the event occurred (required) Event Number unique number for each event (required) One event number per outage/derating Need not be sequential Events that continue through multiple months keeps the originally assigned number 32 RELIABILITY ACCOUNTABILITY

33 One Event for One Outage Event 1 Event 1 Event 1 Month 1 Month 2 Month 3 Event 1 33 RELIABILITY ACCOUNTABILITY

34 Quick Quiz Question: Some generators report a new event record for the same event if it goes from one month to the next or goes from one quarter to the next. What are the advantages of such actions to the GADS statistics? 34 RELIABILITY ACCOUNTABILITY

35 Quick Quiz (cont.) Answer: None! This action distorts the frequency calculation of outages. Increase the work load of the reporter by having them repeat reports. Increases the chances of errors in performance and event records o Hours of outage o Cause codes and event types 35 RELIABILITY ACCOUNTABILITY

36 GADS is a DYNAMIC System Make as many changes as you want, as many times as you want, whenever you want. 36 RELIABILITY ACCOUNTABILITY

37 Report Year-to-date! Report all data year to date with the revision code zero 0 again. If any other changes were made, the reporters and NERC databases would always be the same. It is easier and better to replace the entire database then to append one quarter to the next. 37 RELIABILITY ACCOUNTABILITY

38 Event Identification (cont.) Report Revision Code shows changes to the event record (voluntary) Original Reports (0) Additions or corrections (1, 2, 9) Report all records to a performance report if you revise just one of the records. Event Type describes the event experienced by the unit (required) Inactive Active 38 RELIABILITY ACCOUNTABILITY

39 Unit States 39 RELIABILITY ACCOUNTABILITY

40 Unit States Inactive 40 RELIABILITY ACCOUNTABILITY

41 Unit States Inactive (cont.) Inactive Deactivated shutdown (IEEE 762) as the State in which a unit is unavailable for service for an extended period of time for reasons not related to the equipment. IEEE and GADS interprets this as Inactive Reserve, Mothballed, or Retired 41 RELIABILITY ACCOUNTABILITY

42 Unit States Inactive (cont.) Inactive Reserve (IR) The State in which a unit is unavailable for service but can be brought back into service after some repairs in a relatively short duration of time, typically measured in days. This does not include units that may be idle because of a failure and dispatch did not call for operation. The unit must be on RS a minimum of 60 days before it can move to IR status. Use Cause Code 0002 (three zeros plus 2) for these events. Reliability compliance reports are still enforced!! 42 RELIABILITY ACCOUNTABILITY

43 Unit States Inactive (cont.) Mothballed (MB) The State in which a unit is unavailable for service but can be brought back into service after some repairs with appropriate amount of notification, typically weeks or months. A unit that is not operable or is not capable of operation at a moments notice must be on a forced, maintenance or planned outage and remain on that outage for at least 60 days before it is moved to the MB state. Use Cause Code 9991 for these events. Additional descriptions on MB are being considered by the GADSWG. 43 RELIABILITY ACCOUNTABILITY

44 Unit States Inactive (cont.) Retired (RU) The State in which a unit is unavailable for service and is not expected to return to service in the future. RU should be the last event for the remainder of the year (up through December 31 at 2400). The unit must not be reported to GADS in any future submittals. Use Cause Code 9990 for these events. 44 RELIABILITY ACCOUNTABILITY

45 Note Regarding NERC Compliance When a unit goes into IR or MB, that unit will not be considered in fleet unit reporting statistics like EAF, EFORd, etc. HOWEVER, the unit level compliance MAY still be open for NERC auditing under the NERC Reliability Standards [Critical Infrastructure Protection (CIP); Emergency Preparedness and Operations (EOP); Protection and Control (PRC); etc.]. WECC requires you continue to comply with the standards. Check with your Region for rules. 45 RELIABILITY ACCOUNTABILITY

46 Unit States Active 46 RELIABILITY ACCOUNTABILITY

47 Event Identification (cont.) Event Type (required 17 choices) Two character code describes the event (outage, derating, reserve shutdown, or non-curtailing). EVENT TYPES OUTAGES DERATINGS PO Planned PE Planned Extension MO Maintenance ME Maintenance Extension SF Startup Failure U1 Forced Immediate U2 Forced Delayed PD Planned DP Planned Extension D4 Maintenance DM Maintenance Extension D1 Forced Immediate D2 Forced Delayed D3 Forced Postponed U3 Forced Postponed RS Reserve Shutdown NC Non curtailing 47 RELIABILITY ACCOUNTABILITY

48 Unit States Active (cont.) What is an outage? An outage starts when the unit is either desynchronized (breakers open) from the grid or when it moves from one unit state to another An outage ends when the unit is synchronized (breakers are closed) to the grid or moves to another unit state. In moving from one outage to the next, the time (month, day, hour, minute) must be exactly the same! 48 RELIABILITY ACCOUNTABILITY

49 Outage Types Timing starts WHEN YOU DETECT THE PROBLEM! Forced Outages (four types) Maintenance Outage (one type plus extension) Planned outage (one type plus extension) Forced Outage Maintenance Outage Planned Outage Before the End of next Weekend (U3) 6 hours (U2) Now or very soon (U1) Can t start (SF) After the end of next weekend (MO/ME) Planned Well In Advance (PO/PE) 49 RELIABILITY ACCOUNTABILITY

50 From the Unit States Diagram Unplanned Forced + Maintenance + Planned 50 RELIABILITY ACCOUNTABILITY

51 From the Unit States Diagram Scheduled Forced + Maintenance + Planned 51 RELIABILITY ACCOUNTABILITY

52 Unit States Active (cont.) Scheduled type Outages Planned Outage (PO) o Outage planned Well in Advance such as the annual unit overhaul. o Predetermined duration. o Can slide PO if approved by ISO, Power Pool or dispatch Maintenance (MO) deferred beyond the end of the next weekend but before the next planned event (Sunday 2400 hours) o If an outage occurs before Friday at 2400 hours, the above definition applies. o But if the outage occurs after Friday at 2400 hours and before Sunday at 2400 hours, the MO will only apply if the outage can be delayed passed the next, not current, weekend. o If the outage can not be deferred, the outage shall be a forced event. 52 RELIABILITY ACCOUNTABILITY

53 Unit States Active (cont.) Scheduled type Outages Planned Extension (PE) continuation of a planned outage. Maintenance Extension (ME) continuation of a maintenance outage. 53 RELIABILITY ACCOUNTABILITY

54 Unit States Active (cont.) Extension valid only if: All work during PO and MO events are determined in advance and is referred to as the original scope of work. Do not use PE or ME in those instances where unexpected problems or conditions discovered during the outage result in a longer outage time. PE or ME must start at the same time (month/day/hour/minute) that the PO or MO ended. 54 RELIABILITY ACCOUNTABILITY

55 From GADS DRI PO Planned Outage An outage that is scheduled well in advance and is of a predetermined duration, can last for several weeks, and occurs only once or twice a year. Turbine and boiler overhauls or inspections, testing, and nuclear refueling are typical planned outages. For a planned outage, all of the specific individual maintenance and operational tasks to be performed are determined in advance and are referred to as the "original scope of work." The general task of repairing turbines, boilers, pumps, etc. is not considered a work scope because it does not define the individual tasks to be performed. For example, if a general task such as repair boiler is considered the work scope, it is impossible to conclude that any boiler work falls outside of the original scope of work. Discovery work and re work which render the unit out of service beyond the estimated PO end date are not considered part of the original scope of work. A planned extension may be used only in instances where the original scope of work requires more time to complete than the estimated time. For example, if an inspection that is in the original scope of work for the planned outage takes longer than scheduled, the extra time should be coded as an extension (PE). However, if damage found during the inspection results in an extension of the outage, the extra time required to make repairs should be coded as a forced outage. MO Maintenance Outage An outage that can be deferred beyond the end of the next weekend (defined as Sunday at 2400 hours or as Sunday turns into Monday), but requires that the unit be removed from service, another outage state, or Reserve Shutdown state before the next Planned Outage (PO). Characteristically, a MO can occur any time during the year, has a flexible start date, may or may not have a predetermined duration, and is usually much shorter than a PO. Discovery work and re work which render the unit out of service beyond the estimated MO end date are not considered part of the original scope of work. A maintenance extension may be used only in instances where the original scope of work requires more time to complete than the estimated time. For example, if an inspection that is in the original scope of work for the outage takes longer than scheduled, the extra time should be coded as an extension (ME). If the damage found during the inspection is of a nature that the unit could be put back on line and be operational past the end of the upcoming weekend, the work could be considered MO or ME. If the inspection reveals damage that prevents the unit from operating past the upcoming weekend, the extended work time should be Forced Outage (U1, U2, or U3). Note: If an outage occurs before Friday at 2400 hours (or before Friday turns into Saturday), the above definition applies. But if the outage occurs after Friday at 2400 hours and before Sunday at 2400 hours (the 48 hours of Saturday and Sunday), the MO will only apply if the outage can be delayed past the next, not current, weekend. If the outage cannot be deferred, the outage shall be a forced event. 55 RELIABILITY ACCOUNTABILITY

56 From GADS DRI PE and ME Rules and Regulations The predetermined duration of an outage also determines the estimated completion date of the PO or MO. If the unit is scheduled for four weeks of repairs, then the unit is expected back in service at a certain date four weeks after the start of the outage. In cases where the outage is moved up or back according to the needs of the operating company, ISO, or power pool, then the start of the outage plus duration of the outage determines the new completion date. As long as the outage is no longer than planned, the expected completion date is moved to coincide with the predetermined duration period. If the unit is on outage (for example, U1 outage due to a boiler tube leak) at the time the unit is scheduled to start the PO or MO work, then the work on the cause of the outage (tube repairs) must be completed before changing from the U1 outage to the PO or MO outage. PO and MO work can start but is not counted as PO or MO work until the U1 repairs are complete. All work during PO and MO events is determined in advance and is referred to as the original scope of work. Use ME and PE only in instances where the original scope of work requires more time to complete than originally scheduled. Where applicable, the extension of the planned or maintenance outage may be required to be approved in advance by your power pool or ISO. Advance warning of an extension is very important. However, GADS is not a dispatch orientated database but rather an equipment orientated one. The reporting of the PE and ME is based on IEEE 762 GADS rules, not ISO requirements. Therefore, if the extension meets the GADS rules, then report it as an ME or PE and not a U1 when reporting to GADS only. Do not use ME and PE in instances where unexpected problems or conditions are discovered during the outage which render the unit out of service beyond the estimated end date of the PO or MO. Report these delays as Unplanned (Forced) Outage Immediate (U1). Do not use ME and PE if unexpected problems occur during unit startup. If a unit completes a PO or MO before the original estimated completion date and volunteers to return to service (i.e., the unit is released to dispatch), then any problems causing outages or deratings after that date are not considered to be part of the PO or MO. 56 RELIABILITY ACCOUNTABILITY

57 PE or ME on January 1 at 00:00 Edit program checks to make sure an extension (PE or ME) is preceded by a PO or MO event. Create a PO or MO event for one minute before the PE or ME. Start of Event: End of Event: RELIABILITY ACCOUNTABILITY

58 Forced Outages (FO) U1 Unplanned (Forced) Outage Immediate An outage that requires immediate removal of a unit from service, another Outage State, or a Reserve Shutdown state Requires cause code amplification code ONLY IF the U1 is preceded by the unit being in service (generating power)! T1 - Tripped/shutdown grid separation automatic T2 - Tripped/shutdown grid separation manual 84 - Unknown investigation underway Required As Shown Above 58 RELIABILITY ACCOUNTABILITY

59 Unit States Active (cont.) U1 Unplanned (Forced) Outage Immediate If the U1 is not a trip but the result of a change of state (from planned outage to U1, for example), then the amplification code can be any appropriate amplification code if the reporter chooses to report amplification codes. In-service (generating power) U1 Outage Amp code required = T1 (automatic) or T2 (manual) PO, MO, U1, etc. U1 Outage No amp code required 59 RELIABILITY ACCOUNTABILITY

60 Unit States Active (cont.) Forced type Outages Delayed (U2) does not required immediate removal from service, but requires removal within six (6) hours. This type of outage can only occur start if the unit is in service. Postponed (U3) does not required immediate removal from service but is postponed beyond six (6) hours, and requires removal from service before the end of the next weekend. This type of outage can only start if the unit is in service. Startup Failure (SF) unable to synchronize within a specified period of time or abort startup for repairs. Startup procedure ends when the breakers are closed. 60 RELIABILITY ACCOUNTABILITY

61 Is That Really a U1 Outage? Of the 42,762 FO events in 2016, 84.5% are U1 outages (36,130 events) 9.4 % are SF outages (4,032 events) 4.0 % are U2 outages (1,706 events) 2.1 % is U3 outages (894 events) With U1, you need an cause code amp code! If a boiler leak is detected and the unit remains in service for 2 4 more hours before starting to shut down for repairs, then the boiler tube leak is a U2 event, not a U1. 61 RELIABILITY ACCOUNTABILITY

62 Example #1 Simple Outage Event Description: On January 3 at 4:30 a.m., Riverglenn #1 tripped off line due to high turbine vibration. The cause was the failure of an LP turbine bearing (Cause Code 4240). The unit synchronized on January 8 at 5:00 p.m. 62 RELIABILITY ACCOUNTABILITY

63 Example #1 Simple Outage 700 Capacity (MW) Forced Outage CC Jan 0430 Jan RELIABILITY ACCOUNTABILITY

64 Questions? 64 RELIABILITY ACCOUNTABILITY

65 Examples of Outage Reporting 2017 GADS Data Reporting Workshops Module 05 October, 2017

66 Scenario #1: FO or MO? There was a boiler tube leak 4 days before the scheduled PO. The average repair time for such a leak is 36 hours. The unit cannot stay on line until the next Monday and must come down within 6 hours. Dispatch cleared the unit to come off early for repairs and PO. What type of outage is this? 66 RELIABILITY ACCOUNTABILITY

67 Scenario #1: FO or MO? There was a boiler tube leak 4 days before the scheduled PO. The average repair time for such a leak is 36 hours. The unit cannot stay on line until the next Monday and must come down within 6 hours. Dispatch cleared the unit to come off early for repairs and PO. What type of outage is this? Answer: First 36 hours is a U2 outage to fix tube leak then change to PO. Why? 67 RELIABILITY ACCOUNTABILITY

68 Scenario #1: FO or MO? There was a boiler tube leak 4 days before the scheduled PO. The average repair time for such a leak is 36 hours. The unit cannot stay on line until the next Monday and must come down within 6 hours. Dispatch cleared the unit to come off early for repairs and PO. What type of outage is this? Answer: Whether or not the unit is scheduled for PO, it must come down for repairs before the end of the next weekend. After the repair, the PO can begin! 68 RELIABILITY ACCOUNTABILITY

69 Scenario #2: FO or MO? On Thursday at 10 a.m., the operators discovered vibration on the unit s ID Fan. The unit could stay on line until the next Monday, but dispatch allows the unit to come off line Friday morning. On Friday, the dispatch reviewed the request again and allowed unit to come off for repairs. What type of outage is this? 69 RELIABILITY ACCOUNTABILITY

70 Scenario #2: FO or MO? On Thursday at 10 a.m., the operators discovered vibration on the unit s ID Fan. The unit could stay on line until the next Monday, but dispatch allows the unit to come off line Friday morning. On Friday, the dispatch reviewed the request again and allowed unit to come off for repairs. What type of outage is this? Answer: MO. Why? 70 RELIABILITY ACCOUNTABILITY

71 Scenario #2: FO or MO? On Thursday at 10 a.m., the operators discovered vibration on the unit s ID Fan. The unit could stay on line until the next Monday, but dispatch allows the unit to come off line Friday morning. On Friday, the dispatch reviewed the request again and allowed unit to come off for repairs. What type of outage is this? Answer: The unit could have stayed on line until the end of the next weekend if required. 71 RELIABILITY ACCOUNTABILITY

72 Scenario #3: FO or MO? A gas turbine started vibrating and vibration increased until after peak period. The GT had to come off before the end of the weekend. Dispatch said that the GT would not be needed until the next Monday afternoon. What type of outage is this? 72 RELIABILITY ACCOUNTABILITY

73 Scenario #3: FO or MO? A gas turbine started vibrating and vibration increased until after peak period. The GT had to come off before the end of the weekend. Dispatch said that the GT would not be needed until the next Monday afternoon. What type of outage is this? Answer: FO. Why? 73 RELIABILITY ACCOUNTABILITY

74 Scenario #3: FO or MO? A gas turbine started vibrating and vibration increased until after peak period. The GT had to come off before the end of the weekend. Dispatch said that the GT would not be needed until the next Monday afternoon. What type of outage is this? Answer: The GT is not operable until the vibration is repaired. It could not wait until after the following weekend. 74 RELIABILITY ACCOUNTABILITY

75 Scenario #4: FO or RS? It s Monday. Your combined cycle has a HRSG tube leak and must come off line now. (It s 2x1 but there is no by pass capabilities. ) Dispatch said CC will not be needed for remainder of week. Your management decided to repair the unit on regular maintenance time to save costs. Over the next 36 hours, the HRSG was repaired. (The normal HRSG repairs take 12 hours of maintenance time.) What type of outage is this and for how long? 75 RELIABILITY ACCOUNTABILITY

76 Scenario #4: FO or RS? It s Monday. Your combined cycle has a HRSG tube leak and must come off line now. (It s 2x1 but there is no by pass capabilities. ) Dispatch said CC will not be needed for remainder of week. Your management decided to repair the unit on regular maintenance time to save costs. Over the next 36 hours, the HRSG was repaired. (The normal HRSG repairs take 12 hours of maintenance time.) What type of outage is this and for how long? Answer: FO as long as the unit is not operable full 36 hours then RS. Risk Management (CA). 76 RELIABILITY ACCOUNTABILITY

77 Commercial Availability First developed in the United Kingdom but now used in a number of countries that deregulate the power industry. No equation. Marketing procedure for increasing the profits while minimizing expenditures. The concept is to have the unit available for generation during high income periods and repair the unit on low income periods. 77 RELIABILITY ACCOUNTABILITY

78 Commercial Availability Unit Available Not needed for Generation Not competitive, $ Unit Available Needed for Generation Make Big Revenue, +$ Unit not available Not Needed for Generation Good time for repairs Unit not available Needed for Generation Lost opportunity, $ 78 RELIABILITY ACCOUNTABILITY

79 Scenario #5: PE or FO? During the 4 week PO, the repairs on the Electrostatic Precipitator (ESP) were more extensive then planned. At the end of the 4 week, the ESP work is not completed as outlined in the original scope of work. 3 more days is required to complete the work. What type of outage is the extra 3 days? 79 RELIABILITY ACCOUNTABILITY

80 Scenario #5: PE or FO? During the 4 week PO, the repairs on the Electrostatic Precipitator (ESP) were more extensive then planned. At the end of the 4 week, the ESP work is not completed as outlined in the original scope of work. 3 more days is required to complete the work. What type of outage is the extra 3 days? Answer: PE. Why? 80 RELIABILITY ACCOUNTABILITY

81 Scenario #5: PE or FO? During the 4 week PO, the repairs on the Electrostatic Precipitator (ESP) were more extensive then planned. At the end of the 4 week, the ESP work is not completed as outlined in the original scope of work. 3 more days is required to complete the work. What type of outage is the extra 3 days? Answer: ESP work was part of the original scope of work. 81 RELIABILITY ACCOUNTABILITY

82 Scenario #6: ME or FO? During the 4 week MO, the mechanics discovered Startup BFP seals needed replacing. (not part of scope.) At the end of the 4 week, the SBPF work was not completed because no parts on site. There was 12 hour delay in startup to complete work on SBFP. What type of outage is the extra 12 hours? 82 RELIABILITY ACCOUNTABILITY

83 Scenario #6: ME or FO? During the 4 week MO, the mechanics discovered Startup BFP seals needed replacing. (not part of scope.) At the end of the 4 week, the SBPF work was not completed because no parts on site. There was 12 hour delay in startup to complete work on SBFP. What type of outage is the extra 12 hours? Answer: FO. Why? 83 RELIABILITY ACCOUNTABILITY

84 Scenario #6: ME or FO? During the 4 week MO, the mechanics discovered Startup BFP seals needed replacing. (not part of scope.) At the end of the 4 week, the SBPF work was not completed because no parts on site. There was 12 hour delay in startup to complete work on SBFP. What type of outage is the extra 12 hours? Answer: Not part of original scope and delayed startup by 12 hours. 84 RELIABILITY ACCOUNTABILITY

85 Scenario #7: PO or FO? During the 4 week PO, mechanics discovered ID fan blades needed replacement (outside the scope). Parts were ordered and ID fan was repaired within the 4 week period. No delays in startup. Does the outage change from PO to FO and then back to PO due to unscheduled work? 85 RELIABILITY ACCOUNTABILITY

86 Scenario #7: PO or FO? During the 4 week PO, mechanics discovered ID fan blades needed replacement (outside the scope). Parts were ordered and ID fan was repaired within the 4 week period. No delays in startup. Does the outage change from PO to FO and then back to PO due to unscheduled work? Answer: remains PO for full time. Why? 86 RELIABILITY ACCOUNTABILITY

87 Scenario #7: PO or FO? During the 4 week PO, mechanics discovered ID fan blades needed replacement (outside the scope). Parts were ordered and ID fan was repaired within the 4 week period. No delays in startup. Does the outage change from PO to FO and then back to PO due to unscheduled work? Answer: work completed with scheduled PO time. 87 RELIABILITY ACCOUNTABILITY

88 Scenario #8: PO or FO? A duel fuel combustion turbine was scheduled for an eight day planned outage. The critical path was work on the fuel oil system flow divider. The plant also did some exciter work to attempt to restore the unit MVAR output. After eight days, the work was completed and the unit was placed on line to test, check out, verify that all the repairs were successful. The unit was on line for about an hour when the exciter grounded and tripped the unit. The exciter was sent off to be rewound as a result of this event. The unit remained off for additional days. Is the work to rewind the exciter forced or PO? 88 RELIABILITY ACCOUNTABILITY

89 Scenario #8: PO or FO? A duel fuel combustion turbine was scheduled for an eight day planned outage. The critical path was work on the fuel oil system flow divider. The plant also did some exciter work to attempt to restore the unit MVAR output. After eight days, the work was completed and the unit was placed on line to test, check out, verify that all the repairs were successful. The unit was on line for about an hour when the exciter grounded and tripped the unit. The exciter was sent off to be rewound as a result of this event. The unit remained off for additional days. Forced outage. Why? 89 RELIABILITY ACCOUNTABILITY

90 Scenario #8: PO or FO? A duel fuel combustion turbine was scheduled for an eight day planned outage. The critical path was work on the fuel oil system flow divider. The plant also did some exciter work to attempt to restore the unit MVAR output. After eight days, the work was completed and the unit was placed on line to test, check out, verify that all the repairs were successful. The unit was on line for about an hour when the exciter grounded and tripped the unit. The exciter was sent off to be rewound as a result of this event. The unit remained off for additional days. Forced outage. Why? This is not part of the original scope and is a new failure. 90 RELIABILITY ACCOUNTABILITY

91 Scenario #9: PE or FO? A fossil steam unit had a high efficiency HP turbine installed several years ago. The turbine did not pass the guarantee performance test. The vender agreed to make changes to the steam path so that the turbine would perform as designed. The repairs were scheduled to coincide with a routine planned outage. The turbine inner cylinder was removed and sent to the vender for the steam path repairs. The vender found extensive cracks in the inner cylinder that had to be repaired before the steam path work could be completed. This caused the outage to run approximately 3 weeks past the scheduled end date. From what we know, the crack repair was totally unexpected. Would you call this an extension or a forced outage? 91 RELIABILITY ACCOUNTABILITY

92 Scenario #9: PE or FO? A fossil steam unit had a high efficiency HP turbine installed several years ago. The turbine did not pass the guarantee performance test. The vender agreed to make changes to the steam path so that the turbine would perform as designed. The repairs were scheduled to coincide with a routine planned outage. The turbine inner cylinder was removed and sent to the vender for the steam path repairs. The vender found extensive cracks in the inner cylinder that had to be repaired before the steam path work could be completed. This caused the outage to run approximately 3 weeks past the scheduled end date. From what we know, the crack repair was totally unexpected. Forced Outage. Why? 92 RELIABILITY ACCOUNTABILITY

93 Scenario #9: PE or FO? A fossil steam unit had a high efficiency HP turbine installed several years ago. The turbine did not pass the guarantee performance test. The vender agreed to make changes to the steam path so that the turbine would perform as designed. The repairs were scheduled to coincide with a routine planned outage. The turbine inner cylinder was removed and sent to the vender for the steam path repairs. The vender found extensive cracks in the inner cylinder that had to be repaired before the steam path work could be completed. This caused the outage to run approximately 3 weeks past the scheduled end date. From what we know, the crack repair was totally unexpected. Forced Outage. Why? The repair was unexpected and not part of the work scope. It is important to know the work scope details. 93 RELIABILITY ACCOUNTABILITY

94 Scenario #10 Report Testing Riverglenn #1 completed its steam turbine overhaul when the breaker malfunctioned causing an SF event. Following the breaker repair, the unit tested the steam turbine balance, stop valves and new instrumentation installed during the overhaul as scheduled. What event type should be used to report the testing? PO -Overhaul SF Event Testing 94 RELIABILITY ACCOUNTABILITY

95 Scenario #10 Report Testing Riverglenn #1 completed its steam turbine overhaul when the breaker malfunctioned causing an SF event. Following the breaker repair, the unit tested the steam turbine balance, stop valves and new instrumentation installed during the overhaul as scheduled. What event type should be used to report the testing? PO -Overhaul SF Event Testing PO (and PD if needed). Why? 95 RELIABILITY ACCOUNTABILITY

96 Scenario #10 Report Testing Riverglenn #1 completed its steam turbine overhaul when the breaker malfunctioned causing an SF event. Following the breaker repair, the unit tested the steam turbine balance, stop valves and new instrumentation installed during the overhaul as scheduled. What event type should be used to report the testing? PO -Overhaul SF Event Testing Even though there was a SF event in the middle, the testing is still part of the original PO event work. 96 RELIABILITY ACCOUNTABILITY

97 Scenario #11 Series of Outages Riverglenn #1 was scheduled for a PO on Jan. 8 th but was removed from service on Jan. 2 nd due to boiler tube leak. On Jan. 8 th the unit transitioned into the PO. During the PO, it was discovered that gas exit duct had issues (not part of the OSW) which caused extension of the original PO time by 4 days. The unit was scheduled for a Turbine Over speed Trip testing after the unit was returned to service. Tests were completed and Riverglenn returned to service with several boiler water chemistry holds until boiler water chemistry was good for full rated boiler pressure. 97 RELIABILITY ACCOUNTABILITY

98 Scenario #11 Series of Outages Tube Leak Planned Outage Exit Gas Duct Work Over-speed Testing Silica Holds What are the types of outages/derating for each event? 98 RELIABILITY ACCOUNTABILITY

99 Scenario #11 Series of Outages Tube Leak Planned Outage Exit Gas Duct Work Over-speed Testing Silica Holds U1, U2, U3, MO PO U1 PD Is this a derate? What are the types of outages/derating for each event? 99 RELIABILITY ACCOUNTABILITY

100 More Examples? Appendix G Examples and Recommended Methods 100 RELIABILITY ACCOUNTABILITY

101 A Word of Experience IEEE definitions are designed to be guidelines and are interpreted by GADS. We ask all reporters to follow the guidelines so that uniformity is reporting and resulting statistics. If a unit outage is determined to be a MO, it is an MO by IEEE Guidelines. 101 RELIABILITY ACCOUNTABILITY

102 Testing Following Outages On line testing (synchronized) In testing at a reduced load following a PO, MO, or FO, report the derating as a PD, D4 or the respective forcedtype derating Report all generation Off line testing (not synchronized) Report testing in Additional Cause of Event or Components Worked on During Event Can report as a separate event 102 RELIABILITY ACCOUNTABILITY

103 Black Start Testing A black start test is a verification that a CT unit can start without any auxiliary power from the grid and can close the generator breaker onto a dead line or grid. To set up the test, you isolate the station from the grid, de energize a line, and then give the command for the CT to start. If the start is successful, then you close the breaker onto the dead line. Once completed, you take the unit off, and re establish the line and aux power to the station. You coordinate this test with the transmission line operator, and it is conducted annually. 103 RELIABILITY ACCOUNTABILITY

104 Black Start Testing (cont.) GADS Services surveyed the industry and it was concluded that: It is not an outside management control event. It can be a forced, maintenance or planned event. Use the new cause code RELIABILITY ACCOUNTABILITY

105 Outages Cannot Overlap Acceptable Transition Not Acceptable Transition X Outage #1 Outage #2 Outage #1 Outage #2 Two outages end/start at the same time! Two outages can t occur at the same time! 105 RELIABILITY ACCOUNTABILITY

106 Questions? 106 RELIABILITY ACCOUNTABILITY

107 Derating Event Reporting 2017 GADS Data Reporting Workshops Module 06 October, 2017

108 Unit States (Deratings) What is a derate? A derate exists when a unit cannot generate at 100% capacity A derate starts when the unit is not capable of reaching 100% capacity. A derate ends when the equipment is either ready for or put back in service. Capacity is based on the capability of the unit, not on dispatch requirements. More than one derate can occur at a time. 108 RELIABILITY ACCOUNTABILITY

109 Derating Types Timing starts WHEN YOU DETECT THE PROBLEM! Forced Deratings (three types) Maintenance Deratings (one type plus extension) Planned Deratings (one type plus extension) Forced Derate Maintenance Derate Planned Derate Before the End of next Weekend (D3) 6 hours (D2) Now or very soon (D1) After the end of next weekend (D4/DM) Planned Well In Advance (PD/DP) 109 RELIABILITY ACCOUNTABILITY

110 Unit States (Deratings) Report a derate or not? If the derate is less than 2% NMC AND lasts less than 30 minutes, then it is optional whether you report it or not. All other derates shall be reported! o Report a 1 hour derate with 1% reduction o Report a 15 minute derate with a 50% reduction. 110 RELIABILITY ACCOUNTABILITY

111 Unit Capacity Levels Deratings Ambient related Losses are not reported as deratings report on Performance Record (NMC NDC) System Dispatch requirements are not reported 111 RELIABILITY ACCOUNTABILITY

112 Unit States Active Forced Deratings Immediate (D1) requires immediate reduction in capacity. Delayed (D2) does not require an immediate reduction in capacity but requires a reduction within six (6) hours. Postponed (D3) can be postponed beyond six (6) hours, but requires reduction in capacity before the end of the next weekend. 112 RELIABILITY ACCOUNTABILITY

113 Is That Really a D1 Derate? In 2016, there were 95,887 forced derating events 94.2% are D1 derates (90,273 events) 4.4% are D2 derates (4,228 events) 1.4% are D3 derates (1,386 events) Not all forced derates are D1 events! No derates require amp codes. If the operator detects vibration on a fan and removes it from service 4 hours later, it is a D2, not D1 event. 113 RELIABILITY ACCOUNTABILITY

114 Unit States Active (cont.) Scheduled Deratings Planned (PD) scheduled well in advance and is of a predetermined duration. Maintenance (D4) deferred beyond the end of the next weekend but before the next planned derate (Sunday 2400 Hours). 114 RELIABILITY ACCOUNTABILITY

115 Unit States Active (cont.) Scheduled Deratings (cont.) Planned Extension (DP) continuation of a planned derate. Maintenance Extension (DM) continuation of a maintenance derate. 115 RELIABILITY ACCOUNTABILITY

116 Unit States Active (cont.) GADSWG example of multiple derating extensions for different causes 116 RELIABILITY ACCOUNTABILITY

117 Unit States Active (cont.) Extension valid only if: All work during PD and D4 events are determined in advance and is referred to as the original scope of work. Do not use DP or DM in those instances where unexpected problems or conditions discovered during the outage that result in a longer derating time. DP or DM must start at the same time (month/day/hour/minute) that the PD or D4 ended. 117 RELIABILITY ACCOUNTABILITY

118 Unit Capacity Levels Maximum Capacity Seasonal Derating = Maximum Capacity - Dependable Capacity Dependable Capacity Basic Planned Derating Extended Planned Derating D 1 D 2 D 3 Planned Derating Unplanned Derating Unit Derating= Dependable Capacity - Available capacity Maintenance Available Capacity Note: All capacity and deratings are to be expressed on either gross or net basis. 118 RELIABILITY ACCOUNTABILITY

119 Simple Derating Event Description: On January 10 at 8:00 a.m., Riverglenn #1 reduced capacity by 250 MW due to a fouled north air preheater, leaving a Net Available Capacity (NAC) of 450 MW. Fouling began two days earlier, but the unit stayed on line at full capacity to meet load demand. Repair crews completed their work and the unit came back to full load [700 MW Net Maximum Capacity (NMC)] on January 11 at 4:00 p.m. The Net Dependable Capacity (NDC) of the unit is also 700 MW. 119 RELIABILITY ACCOUNTABILITY

120 Simple Derating Derating Jan 0800 Jan 120 RELIABILITY ACCOUNTABILITY

121 Unit Deratings Deratings that vary in magnitude New event for each change in capacity or, Average the capacity over the full derating time. 121 RELIABILITY ACCOUNTABILITY

122 Unit Deratings Overlapping Deratings All deratings are additive unless shadowed by an outage or larger derating. Shadowed deratings are Noncurtailing on overall unit performance but retained for cause code summaries. Can report shadowed deratings Deratings during load following must be reported. GADS computer programs automatically increase available capacity as derating ends. If two deratings occur at once, choose primary derating; other as shadow. 122 RELIABILITY ACCOUNTABILITY

123 Event Description: Overlapping Deratings - 2nd Starts & Ends Before 1 st Ends Riverglenn #1 had an immediate 100 MW derating on March 9 at 8:45 a.m. due to a failure of the A pulverizer feeder motor. Net Available Capacity (NAC) is 500 MW. At 10:00 a.m. the same day, another 100 MW (NAC = 500 MW) loss occurs with the failure of B pulverizer mill. Failure of the B mill is repaired after 1 hour when a foreign object is removed from the mill. The A motor is repaired and returned to service on March 9 at 6:00 p.m. 123 RELIABILITY ACCOUNTABILITY

124 Overlapping Deratings - 2nd Starts & Ends Before 1 st Ends Capacity (MW) Forced Derating CC 0253 D1 CC /9@:0845 3/9@1000 3/9@1100 3/9@ RELIABILITY ACCOUNTABILITY

125 Dominant Derating Code All deratings remain as being additive unless modifier marked as D Derating modifier marks derating as being dominate, even if another derating is occurring at the same time. No affect on unit statistics. Affects cause code impact reports only. 125 RELIABILITY ACCOUNTABILITY

126 Overlapping Derating - 2nd is Shadowed by the 1 st Event Description: Riverglenn #1 had a D4 event on July 3 at 2:30 p.m. from a condenser maintenance item that reduced the NAC to 590 MW. Fouled condenser tubes (tube side) were the culprit. Maintenance work began on July 5 at 8 a.m. and the event ended on July 23 at 11:45 a.m. On July 19 at 11:45 a.m., a feedwater pump tripped, reducing the NAC and load to 400 MW. This minor repair to the feedwater pump was completed at noon that same day. 126 RELIABILITY ACCOUNTABILITY

127 Overlapping Derating - 2nd is Shadowed by the 1 st Capacity (MW) D4 CC D1 CC /3@1430 7/19@1115 7/19@1200 7/23@ RELIABILITY ACCOUNTABILITY

128 Dominant Derating Code Capacity (MW) 700 Event #1 Event #3 D4 CC D1 CC3410 Event #2 Without Dominant Derating Code 3 events to cover 2 incidents Capacity (MW) 700 Event #1 Event #2 D4 CC D1 CC3410 With Dominant Derating Code 2 events to cover 2 incidents 128 RELIABILITY ACCOUNTABILITY

129 Dominant Derating Code (cont.) How do you know if a derating is dominant? If you re not sure, ask! o Plant control room operator o Plant engineer If you don t mark it dominant, the software will assume it is additive. That can result in inaccurate reporting. 129 RELIABILITY ACCOUNTABILITY

130 Dominant Derating Code (cont.) The following slides show you what happens behind the scenes. However, you do not have to program these derates. They are done automatically for you by your software. All you have to do is indicate that the problem is dominate. 130 RELIABILITY ACCOUNTABILITY

131 Dominant Derating Code (cont.) Normal Deratings Event 1 Event RELIABILITY ACCOUNTABILITY

132 Dominant Derating Code (cont.) Single Dominant Derating Dominant Derating Event RELIABILITY ACCOUNTABILITY

133 Dominant Derating Code (cont.) Overlapping Dominant Deratings Dominant Derating Event 4 Dominant Derating Event 3 Dominant Derating 3 SHADOWS portion of Event RELIABILITY ACCOUNTABILITY

134 Dominant Derating Code (cont.) Overlapping Dominant Deratings by Virtue of Loss Dominant Derating Event 3 Derating Event 4 Derating Event 4 takes the dominant position. 134 RELIABILITY ACCOUNTABILITY

135 Dominant Derating Code (cont.) Advantages are: Shows true impact of equipment outages for big, impact problems Reduces reporting on equipment Shows true frequency of outages. 135 RELIABILITY ACCOUNTABILITY

136 Deratings During Reserve Shutdowns Simple Rules: Maintenance work performed during RS where work can be stopped or completed without preventing the unit from startup or reaching its available capacity is not a derating report on Section D. Otherwise, report as a derating. Estimate the available capacity. 136 RELIABILITY ACCOUNTABILITY

137 Coast Down or Ramp Up From Outage If the unit is coasting to an outage in normal time period, no derating. If the unit is ramping up within normal time (determined by operators), no derating! Nuclear coast down is not a derating UNLESS the unit cannot recover to 100% load as demanded. 137 RELIABILITY ACCOUNTABILITY

138 Questions? 138 RELIABILITY ACCOUNTABILITY

139 Other Event Type Reporting 2017 GADS Data Reporting Workshops Module 07 October, 2017

140 Other Unit States Reserve Shutdown unit not synchronized but ready for startup and load as required. Non curtailing equipment or major component removed from service for maintenance/testing and does not result in a unit outage or derating. Rata testing? Generator Doble testing? 140 RELIABILITY ACCOUNTABILITY

141 Questions? 141 RELIABILITY ACCOUNTABILITY

142 Capacity/Event times Reporting 2017 GADS Data Reporting Workshops Module 08 October, 2017

143 Event Magnitude Impact of the event on the unit (required) 4 elements per record: Start of event End of event Gross derating level Net derating level If you do not report gross or net levels, it will be calculated! 143 RELIABILITY ACCOUNTABILITY

144 Unit Capacity Levels Maximum Capacity Seasonal Derating = Maximum Capacity - Dependable Capacity Dependable Capacity Basic Planned Derating Extended Planned Derating D 1 D 2 D 3 Planned Derating Unplanned Derating Unit Derating= Dependable Capacity - Available capacity Maintenance Available Capacity Note: All capacity and deratings are to be expressed on either gross or net basis. 144 RELIABILITY ACCOUNTABILITY

145 Missing Capacity Calculation! Factors are based on data reported to GADS in 1998 as follows: Fossil units > 0.05 Nuclear units > 0.05 Gas turbines/jets > 0.02 Diesel units > 0.00 Hydro/pumped storage units > 0.02 Miscellaneous units > 0.04 Unless 145 RELIABILITY ACCOUNTABILITY

146 Missing Capacity Calculation! We can use the delta (difference) between your gross and net capacities from your performance records as reported by you to calculate the differences between GAC and NAC on your event records! 146 RELIABILITY ACCOUNTABILITY

147 Event Magnitude (cont.) Start of Event (required) Start month, start day Start hour, start minute Outages start when unit was desynchronized or enters a new outage state Deratings start when major component or equipment taken from service Use 24 hour clock! 147 RELIABILITY ACCOUNTABILITY

148 Event Magnitude (cont.) End of Event (required by year s end) End month, end day End hour, end minute Outage ends when unit is synchronized or, placed in another outage state Derating ends when major component or, equipment is available for service Again, use 24 hour clock 148 RELIABILITY ACCOUNTABILITY

149 Using the 24-hour Clock If the event starts at midnight, use: 0000 as the start hour and start time If the event ends at midnight, use: 2400 as the end hour and end time 149 RELIABILITY ACCOUNTABILITY

150 Event Transitions (Page III-24) There are selected outages that can be back to back; others cannot. Related events are indicated by a yes ; all others are not acceptable. 150 RELIABILITY ACCOUNTABILITY

151 Event Transitions (cont.) Allowable Event Type Changes TO FROM U1 U2 U3 SF MO PO ME PE RS U1 - Immediate Yes No No Yes Yes Yes No No Yes U2 Delayed Yes No No Yes Yes Yes No No Yes U3 Postponed Yes No No Yes Yes Yes No No Yes SF - Startup Failure Yes No No Yes Yes Yes No No Yes MO Maintenance Yes No No Yes Yes Yes Yes No Yes PO Planned Yes No No Yes No Yes No Yes Yes ME Maintenance Extension Yes No No Yes No No Yes No Yes PE Planned Extension Yes No No Yes No No No Yes Yes RS Reserve Shutdown Yes No No Yes Yes Yes No No Yes 151 RELIABILITY ACCOUNTABILITY

152 Question & Answer 152 RELIABILITY ACCOUNTABILITY

153 Quick Quiz Question: Riverglenn #1 reported Event #14 (a Planned Outage PO) from June 3 at 01:00 to July 5 at 03:45. Event #17 is a Unplanned Forced Delayed (U2) Outage from July 5 at 03:45 to July 5 at 11:23 due to instrumentation calibration errors. Are these events reported correctly? 153 RELIABILITY ACCOUNTABILITY

154 Quick Quiz (cont.) Answer: No! The transition from an outage type where the unit out of service to an outage type where the unit is in service is impossible. Question: How do you fix these events? 154 RELIABILITY ACCOUNTABILITY

155 Quick Quiz (cont.) Answer: Change the U2 to an SF 155 RELIABILITY ACCOUNTABILITY

156 Quick Quiz (cont.) Question: Your unit is coming off line for a planned outage. You are decreasing the load on your unit at a normal rate until the unit is off line. Is the time from the when you started to come off line until the breakers are opened a derate? 156 RELIABILITY ACCOUNTABILITY

157 Quick Quiz (cont.) Answer: No. Why? Standard operating procedure. By NERC s standards, it is not a derate. 157 RELIABILITY ACCOUNTABILITY

158 Quick Quiz (cont.) Question: You have finished the planned outage and you are coming up on load. The breakers are closed and you are ramping up at a normal pace. You are able to reach full load in the normal ramp up time (including stops for heat sinking and chemistry.) Is this a derate? 158 RELIABILITY ACCOUNTABILITY

159 Quick Quiz (cont.) Answer: No! All ramp up and safety checks are all within the normal time for that unit. 159 RELIABILITY ACCOUNTABILITY

160 Quick Quiz (cont.) Question: You have finished the planned outage and you are coming up on load. The breakers are closed and you are ramping up at a normal pace. But because of some abnormal chemistry problems, you are not able to reach full load in the normal ramp up time. It takes you 5 extra hours. Is this a derate? 160 RELIABILITY ACCOUNTABILITY

161 Quick Quiz (cont.) Answer: Yes. The 5 hours should be marked as a derate at the level you are stalled. Once the chemistry is corrected and you can go to full load, then the derate ends. 161 RELIABILITY ACCOUNTABILITY

162 Questions? 162 RELIABILITY ACCOUNTABILITY

163 Descripting What Happened? 2017 GADS Data Reporting Workshops Module 09 October, 2017

164 It Takes Team Work to Discovery the Causes of Outages! 164 RELIABILITY ACCOUNTABILITY

165 Primary Event Cause Details of the primary cause of event What caused the outage/derate? May not always be the root cause 165 RELIABILITY ACCOUNTABILITY

166 Primary Event Cause Described by using cause code (required) 4 digit number (See Appendix B) 1,600+ cause codes currently in GADS Points to equipment problem or cause, not a detailed reason for the outage/derate! Set of cause codes for each type of unit. o Cause codes for fossil steam units only o Cause codes for hydro units only 166 RELIABILITY ACCOUNTABILITY

167 Cause Codes for Each Unit Type Fossil Fluidized Bed Fossil Nuclear Diesel Hydro/Pumped Storage Gas Turbine Jet Engine Combined Cycle & Co generator Geothermal 167 RELIABILITY ACCOUNTABILITY

168 Cause Codes for Each Unit Type Example of two names, different units: Fossil steam Combined cycle Desuperheater/attemperator piping Desuperheater/attemperator valves 6140 HP Desuperheater/attemperator piping Greater than 600 PSIG HP Desuperheater/attemperator valves 168 RELIABILITY ACCOUNTABILITY

169 What are Amplification Codes? Alpha character to describe the failure mode or reason for failure (Appendix J) Located in blank column next to cc. Used by CEA and IAEA as modifiers to codes for many years. Increases the resources of cause codes without adding new codes. Many same as Failure Mechanisms (Appendix H) Required for U1 events only; strongly recommended for all other events. 169 RELIABILITY ACCOUNTABILITY

170 Example of Amplification Code C0 = Cleaning E0 = Emission/environmental restriction F0 = Fouling 45 = Explosion 53 = Inspection, license, insurance 54 = Leakage P0 = Personnel error R0 = Fire 170 RELIABILITY ACCOUNTABILITY

171 Example of Amplification Code Boiler (feedwater) pump packing leak. Cause code 3410; amp code 54 HP Turbine buckets or blades corrosion Cause code 4012; amp code F0 Operator accidentally tripped circulating water pump Cause code 3210; amp code P0 Does anyone agree with this? 171 RELIABILITY ACCOUNTABILITY

172 Event Contribution Codes Contribution Codes (voluntary) 1 Primary cause of event there can only be one primary cause for forced outages. There can be multiple primary causes for PO and MO events only. 2 Contributed to primary cause of event contributed but not primary. 3Work done during the event worked on during event but did not initiate event. 5After startup, delayed unit from reaching load point Note: No codes 6 or 7 as of January 1, RELIABILITY ACCOUNTABILITY

173 Event Contribution Codes (cont.) Contribution Codes Can use event contribution code 1 (Primary cause of event) on additional causes of events during PO and MO events only and not any forced outages or derates! Must use event contribution code 2 to 5 on any additional causes of events during any forced outage or derate. 173 RELIABILITY ACCOUNTABILITY

174 Primary Event Cause (cont.) Time: Work Started/Time: Work Ended (voluntary) Uses 24 hour clock and looks at event start & end dates & times. Problem Alert (voluntary) Man Hours Worked (voluntary) Verbal Description (voluntary but encouraged) Most helpful information is in the verbal descriptions IF they are completed correctly. 174 RELIABILITY ACCOUNTABILITY

175 Types of Failures (III-34, App. H) Erosion Corrosion Electrical Electronic Mechanical Hydraulic Instruments Operational (Same as Amplification Codes) (voluntary) 175 RELIABILITY ACCOUNTABILITY

176 Typical Contributing Factors (voluntary) Foreign/Wrong Part Foreign/Incorrect Material Lubrication Problem Weld Related Abnormal Load Abnormal Temperature Normal Wear Particulate Contamination Abnormal Wear Set Point Drift Short/Grounded Improper Previous Repair 176 RELIABILITY ACCOUNTABILITY

177 Typical Corrective Actions (voluntary) Recalibrate Adjust Temporary Repair Temporary Bypass Redesign Modify Repair Part(s) Replace Part(s) Repair Component(s) Reseal Repack Request License Revision 177 RELIABILITY ACCOUNTABILITY

178 Compare the difference... Method 1 Cause Code 1000 U1 Outage The unit was brought off line due to water wall leak Method 2 Cause Code 1000 U1 Outage Leak. 3 tubes eroded from stuck soot blower. Replaced tubes, soot blower lance. 178 RELIABILITY ACCOUNTABILITY

179 Additional Causes of Event (voluntary) Same layout as primary outage causes Used to report factors contributing to the cause of event, additional work, factors affecting startup/ramp down Up to 46 additional repair records allowed 179 RELIABILITY ACCOUNTABILITY

180 Expanded Data Reporting (III-36-38, App. H) (voluntary) For gas turbines and jet engines Optional but strongly encouraged Failure mechanism (columns 50 53) Same as Amplification Codes Trip mechanism (manual or auto) (column 54) Cumulative fired hours at time of event (columns 55 60) Cumulative engine starts at time of event (columns 61 65) 180 RELIABILITY ACCOUNTABILITY

181 Question & Answer 181 RELIABILITY ACCOUNTABILITY

182 Quick Quiz Question: Riverglenn #1 (a fossil unit) came down for a boiler overhaul on March 3rd. What is the appropriate cause code for this event? 182 RELIABILITY ACCOUNTABILITY

183 Quick Quiz (cont.) Answer: 1800 Major Boiler overhaul more than 720 hours 1801 Minor Boiler overhaul 720 hours or less 183 RELIABILITY ACCOUNTABILITY

184 Quick Quiz (cont.) Question: Riverglenn #2 experienced a turbine overhaul from September 13 to October 31. A number of components were planned for replacement, including the reblading of the high pressure turbine (September 14 October 15). What are the proper Cause Codes and Contribution Codes for this outage? 184 RELIABILITY ACCOUNTABILITY

185 Quick Quiz (cont.) Answer: Major Turbine overhaul Cause Code 4400 Contribution Code 1 High Pressure Turbine reblading Cause Code 4012 Contribution Code RELIABILITY ACCOUNTABILITY

186 Quick Quiz (cont.) Question: The following non curtailing event was reported on a 300 MW unit: Started January 1300 Ended January 0150 Cause Code 3410 (Boiler Feed Pump) Gross Available Capacity: * Net Available Capacity: 234 MW Is everything okay with this description? 186 RELIABILITY ACCOUNTABILITY

187 Quick Quiz (cont.) Answer: The capacity of the unit during the NC should not be reported because the unit was capable of 100% load. Only report GAC and NAC when the unit is derated. (See Page III 18, last paragraph.) If GAC or NAC is reported with an NC, the editing program shows a warning only. 187 RELIABILITY ACCOUNTABILITY

188 Quick Quiz (cont.) Question: Riverglenn #1 experienced the following event: Event Type: D4 Start Date/Time: September 3; 1200 End Date/time: September 4; 1300 GAC: NAC: 355 Cause Code: 1486 Is this event reported correctly? 188 RELIABILITY ACCOUNTABILITY

189 Quick Quiz (cont.) Answer: The GAC is blank, causing an error. Put value in GAC space or Place * in GAC space NERC no longer recognizes cause code 1486 (starting in 1993). Use Cause Code 0265 instead. See Page Appendix B RELIABILITY ACCOUNTABILITY

190 Quick Quiz (cont.) Question: Riverglenn #1 experienced a FO as follows: Start date/time: October 1545 End date/time: October 1321 GAC: NAC: Cause Code: 1455 Description: ID fan vibration, fly ash buildup on blades Is this event reported correctly? 190 RELIABILITY ACCOUNTABILITY

191 Quick Quiz (cont.) Answer: 1. The start time of the event is after the end time. 2. Looking at the description of the event, the better cause code would be 1460 (fouling of ID Fan) rather than just ID Fan general code RELIABILITY ACCOUNTABILITY

192 Questions? 192 RELIABILITY ACCOUNTABILITY

193 Performance Data Reporting 2017 GADS Data Reporting Workshops Module 10 October, 2017

194 Performance Reporting (Section IV) 194 RELIABILITY ACCOUNTABILITY

195 Why Collect Performance Records? Performance data provides information, in a summarized format, pertaining to overall unit operation during a particular month in a given year. This data is needed to calculate unit performance, reliability, and availability statistics. Starting Reliability Equivalent Forced Outage Rate Demand (EFORd) Performance data is required for all unit types and sizes reported to the GADS program. 195 RELIABILITY ACCOUNTABILITY

196 Why Collect Performance Records? Double check against event records Event and performance hours must match down to 0.03 hrs. Monthly fuels Monthly generation Annual, monthly, seasonal, or rolling reports 196 RELIABILITY ACCOUNTABILITY

197 Performance Report Only the 05 format is accepted by WebE-GADS. To check if your program is using the correct format Open the performance file (in text format) with Notepad. If the first two digits of the file are 05, then you are okay. If the first two digits of the file are 95, then update your software. All performance text files must have the extension txt or it will not upload to WebE-GADS. Data is due 45 days after the end of each quarter year. Monthly or year-to-date data is accepted by WebE-GADS. Strongly recommend year-to-date submittals! 197 RELIABILITY ACCOUNTABILITY

198 Unit Identification Record Code the 05 uniquely identifies the data as a performance report (required) Utility (Company) Code a three digit code that identifies the reporting organization (required) Unit Code a three digit code that identifies the unit being reported. This code also distinguishes one unit from another in your utility (required) 198 RELIABILITY ACCOUNTABILITY

199 Unit Identification (cont.) Year is the year of the performance record (required) Report Period is the month (required) Report Revision Code shows changes to the performance record (voluntary) Original Reports (0) Additions or corrections (1, 2, 9) Report all records to a performance report if you revise just one of the records. 199 RELIABILITY ACCOUNTABILITY

200 Unit Generation Performance The data provided in this section are used to calculate performance statistics. Both gross and net values are requested. Net values are preferred but reporting gross data only is acceptable. Reporting (either) gross and (or) net data depends on how the unit is electrically metered. If you meter on a single basis, but can estimate the other, do so and enter the estimated value in the appropriate field. 200 RELIABILITY ACCOUNTABILITY

201 Gross Vs. Net Capacities Electric Production Generator Gross Generation Meter GMC, GDC Gross Generation Internal plant or auxiliary use Power out to The customer Net Generation Meter NMC, NDC Net Generation 201 RELIABILITY ACCOUNTABILITY

202 Unit Generation (cont.) Gross Maximum Capacity (GMC) Maximum sustainable capacity (no derates) Proven by testing Capacity not affected by equipment unless permanently modified Gross Dependable Capacity (GDC) Level sustained during period without equipment, operating or regulatory restrictions Gross Actual Generation (voluntary) Power generated before auxiliaries You are encouraged to report Gross numbers!! 202 RELIABILITY ACCOUNTABILITY

203 Dependable Capacities GDC is the gross power level that the unit can sustain during a given period if there are no equipment, operating, or regulatory restrictions. By definition, therefore, the GDC is the GMC modified for ambient limitations. GMC (Ambient Losses) = GDC Ambient limits refer to outside, weather related losses, to the unit and not related to equipment. For example, your ID Fans are designed to pull air with a maximum temperature of 100⁰ F and it is 110⁰ F. 203 RELIABILITY ACCOUNTABILITY

204 Gross Actual Generation (GAG) The actual number of gross electrical mega watthours (MWh) generated by the unit during the month. If you report both Service Hours and Gross Actual Generation (one to ), then GMC or GDC must also be reported. If both service hours and a gross capacity value are reported, Gross Actual Generation must also be reported. GAG will always be zero or positive! 204 RELIABILITY ACCOUNTABILITY

205 Unit Generation (cont.) Net Maximum Capacity (NMC) GMC less any capacity utilized for unit s station services (no derates). Capacity not affected by equipment unless permanently modified. Net Dependable Capacity (NDC) GDC less any capacity utilized for that unit s station services. Net Actual Generation (required) Power generated after auxiliaries. Can be negative if more aux than gross! 205 RELIABILITY ACCOUNTABILITY

206 Dependable Capacities NDC is the net power level that the unit can sustain during a given period if there are no equipment, operating, or regulatory restrictions. By definition, therefore, the NDC is the NMC modified for ambient limitations. NMC (Ambient Losses) = NDC Ambient limits refer to outside, weather related losses, to the unit and not related to equipment. For example, your ID Fans are designed to pull air with a maximum temperature of 100⁰ F and it is 110⁰ F. 206 RELIABILITY ACCOUNTABILITY

207 Net Actual Generation (NAG) The actual number of net electrical mega watt hours (MWh) generated by the unit during the month. If you report both Service Hours and Net Actual Generation (one to ), then NMC or NDC must also be reported. If both service hours and a net capacity value are reported, Net Actual Generation must also be reported. Negative NAG can be reported and will be accepted. 207 RELIABILITY ACCOUNTABILITY

208 Gas Turbine/Jet Capacities GT & Jets capacities do not remain as constant as fossil/nuclear units. International Organization of Standardization (ISO) standard for the unit at Standard Temperatures and Pressures (STP based on environment) should be the GMC/NMC measure. Output less than ISO number is unit GDC/NDC. Average capacity number for month is reported to GADS 208 RELIABILITY ACCOUNTABILITY

209 Effect of Ambient Temperature 209 RELIABILITY ACCOUNTABILITY

210 Missing Capacity Calculation! If any capacity (capacities) is (are) not reported, the missing capacities will be calculated based on all reported numbers. For example, if only the NDC is reported and the NDC = 50, then: NDC = NMC = 50 GMC = NMC times (1 + factor) GDC = NDC times (1 + factor) GAG = NAG times (1 + factor) 210 RELIABILITY ACCOUNTABILITY

211 Missing Capacity Calculation! If you only report either the gross or the net capacities, then the GADS editing program or WebE-GADS will calculate any missing GMC, GDC, NMC, or NDC as follows: Unit Type Fossil, Nuclear, and Fluidized Bed: Gas Turbine/Jet Engine: Diesel: Hydro/Pumped Storage: Miscellaneous: Difference 5.0% difference between gross and net values 2.0% difference between gross and net values No difference between gross and net values 2.0% difference between gross and net values 4.0% difference between gross and net values Note: these percentages may change in the future! 211 RELIABILITY ACCOUNTABILITY

212 Missing Capacity Calculation! Capacities are needed to edit and calculate unit performances. If you don t like the new capacities or generation numbers calculated, then complete the RIGHT number in the reports. GADS will not overwrite existing numbers! 212 RELIABILITY ACCOUNTABILITY

213 Quick Quiz Question: Suppose your utility only collects net generation numbers. What should you do with the gross generation fields? 213 RELIABILITY ACCOUNTABILITY

214 Quick Quiz (cont.) Answer: Leave the field blank or place asterisks (*) in the gross max, gross dependable, and gross generation fields. The editing program recognizes the blank field or the * and will look only to the net sections for data. 214 RELIABILITY ACCOUNTABILITY

215 Unit Loading (voluntary) Typical Unit Loading Characteristics Unit loading is how the unit was operated or loaded during the month being reported. If the unit was off line during the entire period, describe how the unit typically would have been loaded had it been on line. Code Description 1 Base loaded with minor load-following at night and on weekends 2 Periodic startups with daily load-following and reduced load nightly 3 Weekly startup with daily load-following and reduced load nightly 4 Daily startup with daily load-following and taken off-line nightly 5 Startup chiefly to meet daily peaks 6 Other (see verbal description) 7 Seasonal Operation (winter or summer only) 215 RELIABILITY ACCOUNTABILITY

216 Attempted & Actual Unit Starts Attempted Unit Starts (required) Attempts to synchronize the unit Repeated failures for the same cause without attempted corrective actions are considered a single start Repeated initiations of the starting sequence without accomplishing corrective repairs are counted as a single attempt. For each repair, report 1 attempted starts. Actual Unit Starts (required) Unit actually synchronized to the grid 216 RELIABILITY ACCOUNTABILITY

217 Attempted & Actual Unit Starts If you report actual start, you must report attempted. If you do not keep track then: Leave Starts Blank GADS editor will estimate both attempted and actual starts based on event data using the formula: Actual Unit Starts + Start-Up Failures = Attempted Unit Starts The GADS program also accepts 0 in the attempts field if actual = 0 also. 217 RELIABILITY ACCOUNTABILITY

218 Unit Time Information Service Hours (SH) (required) Number of hours synchronized to system (Driving your car to work.) Reserve Shutdown Hours (RSH) (required) Available for load but not used (economic) (Your car in the garage or a parking lot while you are shopping.) 218 RELIABILITY ACCOUNTABILITY

219 Unit Time Information (cont.) Pumping Hours (required) Hours the hydro turbine/generator operated as a pump/motor Synchronous Condensing Hours (required) Unit operated in synchronous mode Hydro, pumped storage, gas turbine, and jet engines Its field is controlled by a voltage regulator to either generate or absorb reactive power as needed to adjust the grid's voltage, or to improve power factor. Available Hours (AH) (required) Sum of SH+RSH+Pumping Hours+ synchronous condensing hours 219 RELIABILITY ACCOUNTABILITY

220 Unit Time Information (cont.) Planned Outage Hours (POH) (required) Outage planned Well in Advance such as the annual unit overhaul. Predetermined duration. Can slide PO if approved by ISO, Power Pool or dispatch Forced Outage Hours (FOH) (required) Requires the unit to be removed from service before the end of the next weekend (before Sunday 2400 hours) Maintenance Outage Hours (MOH) (required) Outage deferred beyond the end of the next weekend (after Sunday 2400 hours). 220 RELIABILITY ACCOUNTABILITY

221 Unit Time Information (cont.) Extensions of Scheduled Outages (ME, PE) (required) Includes extensions from MOH & POH beyond its estimate completion date or predetermined duration. Extension is part of original scope of work and problems encountered during the PO or MO. If problems not part of Original Scope of Work (OSW), then extended time is a forced outage. ISO and power pools must be notified in advance of any extensions whether ME, PE, or U RELIABILITY ACCOUNTABILITY

222 Unit Time Information (cont.) Unavailable Hours (UAH) (required) Sum of POH+FOH+MOH+PE+ME Period Hours or Active (PH) (required) Sum of Available + Unavailable Hours Inactive Hours (IH) (required) The number of hours the unit is in the inactive state (Inactive Reserve, Mothballed, or Retired.) Discussed later in detail. 222 RELIABILITY ACCOUNTABILITY

223 Unit Time Information (cont.) Calendar Hours Sum of Period Hours + Inactive Hours For most cases, Period Hours = Calendar Hours 223 RELIABILITY ACCOUNTABILITY

224 Quick Quiz Question: The GADS editing program will only accept 744 hours for January, March, May, etc; 720 hours for June, September, etc; 672 for February. (It also adjusts for daylight savings time.) But there are two exceptions where it will let you report any number of hours in the month. What are these? 224 RELIABILITY ACCOUNTABILITY

225 Quick Quiz (cont.) Answer: When a unit goes commercial. The program checks the design data for the date of commercial operation and will accept any data after that point. Start reporting a new unit or transfer of a unit from one owner to the next at the beginning of the month. When the unit retires or is taken out of service for several years, the GADS staff must modify the performance files to allow the data to pass the edits. Report the retired unit until the end of the month. 225 RELIABILITY ACCOUNTABILITY

226 Quick Quiz (cont.) Question (3 answers): Suppose you receive a performance error message for your 500 MW NMC unit that states you reported 315,600 MW of generation but the GADS editing program states the generation should only be 313,000 MW? You reported 625 SH, 75 RSH, and 44 MO. Hint: {[NMC+1] x (SH)] + 10%} 226 RELIABILITY ACCOUNTABILITY

227 Quick Quiz (cont.) Answers: Check the generation of the unit to make sure it is 315,600 MW Check the Service Hours of the unit. Check the NMC of the unit. You can adjust NMC each month. 227 RELIABILITY ACCOUNTABILITY

228 Primary Fuel Can report from one to four fuels Primary (most thermal BTU) fuel Not required for hydro/pumped storage units Required for all other units, whether operated or not 228 RELIABILITY ACCOUNTABILITY

229 Primary Fuel (cont.) Fuel Code (required) Quantity Burned (voluntary) Average Heat Content (voluntary) % Ash (voluntary) %Moisture (voluntary) % Sulfur (voluntary) % Alkalis (voluntary) Grindability Index (coal only)/ % Vanadium and Phosphorous (oil only) (voluntary) Ash Softening Temperature (voluntary) 229 RELIABILITY ACCOUNTABILITY

230 Fuel Codes Fuel Codes Code Description Code Description CC Coal PR Propane LI Lignite SL Sludge Gas PE Peat GE Geothermal WD Wood NU Nuclear OO Oil WM Wind DI Distillate oil SO Solar KE Kerosene WH Waste Heat JP JP4 or JP5 OS Other Solid (Tons) WA Water OL Other Liquid (BBL) GG Gas OG Other Gas (Cu. Ft.) 230 RELIABILITY ACCOUNTABILITY

231 Question & Answer 231 RELIABILITY ACCOUNTABILITY

232 Quick Quiz Question: Utility X reported the following data for the month of January for their gas turbine Jumbo #1: Service Hours: 4 Reserve Shutdown Hours: 739 Forced Outage Hours: 1 Fuel type: NU Any problems with this report? 232 RELIABILITY ACCOUNTABILITY

233 Quick Quiz (cont.) Answer: There is no such thing as a nuclear powered gas turbine! 233 RELIABILITY ACCOUNTABILITY

234 Quick Quiz (cont.) Question: Suppose you operate a gas turbine that has 100 NMC in the winter (per the ISO charts). During the winter months, you can produce 100 MW NDC. What is your season derating on this unit during the winter? 234 RELIABILITY ACCOUNTABILITY

235 Quick Quiz (cont.) Answer: There is no derating! NMC NDC = = 0 (zero) 235 RELIABILITY ACCOUNTABILITY

236 Quick Quiz (cont.) Question: Suppose you operate a gas turbine that has 100 NMC in the winter (per the ISO charts) and 95 NMC in the summer (per the ISO charts). During the summer months, you can produce 95 NDC. What is your season derating on this unit during the summer? 236 RELIABILITY ACCOUNTABILITY

237 Quick Quiz (cont.) Answer: There is no derating! NMC NDC = = 0 (zero) ISO charts and operating experience determine capability of GTs and other units. DO NOT ASSUME ALL GT OPERATE AT SAME CAPACITY YEAR AROUND! (Winter NMC = Summer NMC for GTs) 237 RELIABILITY ACCOUNTABILITY

238 Questions? 238 RELIABILITY ACCOUNTABILITY

239 Outside Management Control (OMC) 2017 GADS Data Reporting Workshops Module 11 October, 2017

240 Outside Management Control (OMC) 240 RELIABILITY ACCOUNTABILITY