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1. G. Michael CurleyManager of GADS ServicesOctober 27-29, 2010 NERC GADS 101Data Reporting Workshop
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3. Overview of Attendees at this Conference Representatives of:
Generating companies (IOU, IPPs, Government, etc)
Consultants
Insurance
ISOs 3
4. What’s in the folder? Agenda
List of attendees (as of October 20, 2010)
Changes to the 2011 DRI
Slides for GADS 101 Data Reporting Workshop
Slides for GADS Wind Data Reporting Workshop
Slides for Benchmarking Seminar
Slides for pc-GAR and pc-GAR MT Workshop
Slides for Unit Design Data Entry Program
Flash drive 4
5. What’s on the flash drive? Same as the folder plus …
GADS Data Reporting Instructions (effective January 1, 2011)
GADS Data Editing Program
GADS Services Pricing Schedule
pc-GAR and pc-GAR MT Demo Software
pc-GAR Order Forms
GADS Wind Turbine Generation Data Reporting Instructions
GADS Wind Generation Data Entry Software
WEC Studies 5
6. Agenda Introduction and welcoming remarks
What is NERC?
What is GADS?
Fundamentals on the three GADS Databases
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7. Agenda (cont.) IEEE 762 Equations and their meanings
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.
Data release policies
What’s new with GADS?
Closing Comments 7
8. 8
9. NERC Background NERC started in 1968.
NERC chosen as the ERO for the US in 2006. Started developing the “Rules of Procedure” to manage the bulk power supply.
BPS consists of the transmission and generation facilities.
NERC changed from “council” to “corporation” in January 2007.
From 2007 to now, NERC became the ERO of 6 of the 10 Canadian Provinces. 9
10. Energy Policy Act of 2005 Signed by President Bush in August 2005
The reliability legislation amends Part II of the Federal Power Act to add a section 215 making reliability standards for the bulk- power system mandatory and enforceable.
Electric Reliability Organization (ERO)
Not a governmental agency or department
Same purpose: “To keep the lights on” but with more power to do so. 10
11. Energy Policy Act of 2005 “Bulk-power System” means the facilities and control systems necessary for operating an interconnected electric energy transmission network (or any portion thereof) and electric energy from generation facilities needed to maintain transmission system reliability. The term does not include facilities used in the local distribution of electric energy. 11
12. About NERC Develop & enforce reliability standards
Analyze system outages and near-misses & recommend improved practices
Assess current and future reliability
12 Good afternoon and thank you for the invitation to speak with you today.
As you’ve heard, my name is Rick Sergel. I am the President & CEO of the North American Electric Reliability Corporation, an international self-regulatory authority responsible for the reliability of the bulk power transmission and generation system in North America. Granted the authority to develop and enforce reliability standards through the Energy Policy Act of 2007, NERC is able to levy fines of up to one million dollars per day per violation of our standards. NERC holds similar authority in a number of Canadian provinces and is seeking recognition in Canada.
As part of this, we:
Develop and enforce mandatory standards that apply to all owners, operators and users of the electric grid system;
Assess and report on future reliability and adequacy of electricity supply and delivery systems;
Monitor the past and current performance of the bulk power system;
Evaluate the preparedness of those that operate the bulk power system; and
Train and educate others about our standards and compliance programs and certifying electric system operators.
Good afternoon and thank you for the invitation to speak with you today.
As you’ve heard, my name is Rick Sergel. I am the President & CEO of the North American Electric Reliability Corporation, an international self-regulatory authority responsible for the reliability of the bulk power transmission and generation system in North America. Granted the authority to develop and enforce reliability standards through the Energy Policy Act of 2007, NERC is able to levy fines of up to one million dollars per day per violation of our standards. NERC holds similar authority in a number of Canadian provinces and is seeking recognition in Canada.
As part of this, we:
Develop and enforce mandatory standards that apply to all owners, operators and users of the electric grid system;
Assess and report on future reliability and adequacy of electricity supply and delivery systems;
Monitor the past and current performance of the bulk power system;
Evaluate the preparedness of those that operate the bulk power system; and
Train and educate others about our standards and compliance programs and certifying electric system operators.
13. Meeting Demand in Real Time 13
14. About NERC: Regional Entities (RE) 14 8 Regional Reliability Organizations
4 synchronous Interconnections
8 Regional Reliability Organizations
4 synchronous Interconnections
15. What does NERC do? Sets reliability standards (96 in place; 24 being reviewed)
Monitors compliance with reliability standards
Provides education and training resources
Conducts reliability assessments
Facilitates reliability information exchange
Supports reliable system operation and planning
Certifies reliability organizations and personnel
Coordinates security of bulk electric system
Cyber attacks
Pandemics
Geomagnetic disturbances 15
16. One of the first orders of business… Create a transmission database
Transmission Availability Data System (TADS)
200 kV and above.
Currently 2 years of data in TADS 16
17. Work now… Marry the transmission to the generation databases, using Section 1600 of the Rules of Procedure. 17
18. GADS Task Force Talked about mandatory GADS reporting for many years.
In June 2010, the NERC Planning Committee (PC) approved a task force to determine if GADS should be mandatory and to what level.
About 77% of the installed capacity already report to GADS.
Voluntary database now.
To date, the GADSTF is recommending mandatory reporting of GADS data. 18
19. Rules of Procedure: Section 1600Overview NERC’s authority to issue a mandatory data request in the U.S. is contained in FERC’s rules. Volume 18 C.F.R. Section 39.2(d) states: “Each user, owner or operator of the Bulk-Power System within the United States (other than Alaska and Hawaii) shall provide the Commission, the Electric Reliability Organization and the applicable Regional Entity such information as is necessary to implement section 215 of the Federal Power Act as determined by the Commission and set out in the Rules of Procedure of the Electric Reliability Organization and each applicable Regional Entity.” 19
20. Rules of Procedure: Section 1600Request Details A complete data request includes:
a description of the data or information to be requested, how the data or information will be used, and how the availability of the data or information is necessary for NERC to meet its obligations under applicable laws and agreements
a description of how the data or information will be collected and validated
a description of the entities (by functional class and jurisdiction) that will be required to provide the data or information (“reporting entities”)
the schedule or due date for the data or information
a description of any restrictions on disseminating the data or information (e.g., “confidential,” “critical energy infrastructure information,” “aggregating” or “identity masking”)
an estimate of the relative burden imposed on the reporting entities to accommodate the data or information request 20
21. Rules of Procedure: Section 1600Procedure 21
22. Rules of Procedure: Section 1600Limitations NERC Registered Entities
Subject to FERC Rules
Data Request does not carry the same penalties to non-U.S. entities.
However, all NERC Registered Entities, regardless of their country of origin, must comply with the NERC Rules of Procedure, and as such, are required to comply with Section 1600 22
23. What if a GO doesn’t comply? Possible NERC actions:
From Rule 1603: “Owners, operators, and users of the bulk power system registered on the NERC Compliance Registry shall comply with authorized requests for data and information.” The data request must identify which functional categories are required to comply with the request. In this case, it presumably would be Generation Owners.
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24. What if a GO doesn’t comply? Possible NERC actions:
NERC will audit the GADS data submittals through logical evaluations of the data reported and that previously reported by the entity. Reconciliation findings will be reviewed with the reporting entity.
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25. What if a GO doesn’t comply? Possible NERC actions:
NERC may resort to a referral to FERC for only United States entities, not Canadian entities. NERC will make use of the mechanisms it has available for both U.S. and Canadian entities (notices, letters to CEO, requests to trade associations for assistance, peer pressure) to gain compliance with the NERC Rules. A failure to comply with NERC Rules could also be grounds for suspension or disqualification from membership in NERC. Whether or not NERC chooses to use that mechanism will likely depend on the facts and circumstances of the case.
NERC cannot impose penalties for a failure to comply with a data request. 25
26. What if a GO doesn’t comply? Possible FERC actions:
All members of NERC (US and Canadian) are bound by their membership agreement with NERC to follow NERC’s Reliability Standards and Rules of Procedure, including section 1600.
Under section 215 of the Federal Power Act, FERC has jurisdiction over all users, owners, and operators of the bulk power system within the United States.
FERC could treat a failure by a U.S. entity to comply with an approved data request as a violation of a rule adopted under the Federal Power Act using its enforcement mechanisms in Part III of the FPA.
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27. What if a GO doesn’t comply? What about Canada?
Canadian provinces who have signed agreements stating they recognize NERC’s ERO status, will be compliant with the NERC approved standards and Rules of Procedure issued by the NERC Board.
The obligation arises for the Canadian utilities if they are members of NERC. For example, if Canadian Utility “A” is a member of NERC, then it must go by the Rules of Procedure, standards, etc. If Canadian Utility “X” is not a NERC member but its providence recognizes NERC as their ERO, then Utility “X” is not under obligation to follow the rules. 27
28. GADS vs. ISO Data Collection Rules Currently, GADS sets data collection rules for use on a national basis; each ISO can set the rule for data collection within their jurisdiction.
Here are special rules that GADS suggests for hydro units.
As of August 5, 2008 we considered a draft of the rules.
A more “final set of rules” is now Appendix M of the GADS Data Reporting Instructions issued January 2010.
One recommendation of GADSTF is one set of rules for all (coordination between GADS and ISOs). 28
29. More information? Please visit our website: www.nerc.com
Most information is open to the public.
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30. 30
31. What is GADS?
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32. What is GADS? Analyze the past (1982-2009)
Conduct special studies like high impact/low probability (HILP) studies
Perform benchmarking services
Monitor the present (2010 data)
Track current unit performance
Assess the future
Predict the future performance of units 32
33. Example – Benchmarking – Distributions 33
34. Example – Benchmarking – Top Problems 34
35. What is meant by “Availability?” 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! 35
36. Monitor the Present 36
37. International GADS Users Malaysia *
Ireland *
Brazil *
India *
Peoples Republic of China
Spain
New Zealand
South Korea
Parts of S. America
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38. GADS 2009 Data Reporting 38
39. Why GADS? Provide NERC committees with information on availability of power plant for analyzing grid reliability and national security issues.
Provide energy marketers with data on the reliability of power units.
Assist planning of future facilities.
Help in setting goals for production and maintenance. 39
40. Why GADS? Evaluating new equipment products and plant designs.
Assisting in prioritizing repairs for overhauls.
Help planners with outage down timing and costs.
Provide insights on equipment problems and preventative outages. 40
41. Why GADS? Benchmarking existing units to peers.
Provide a source of backup data for insurance, governmental inquiries and investigations, and lose of hard drives.
Working to find answers to questions not asked.
Economic dispatch records
Generation owners in several regions
Track units bought and sold
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42. 42
43. The GADS Data Monster 43
44. 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.
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45. 45
46. 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. 46
47. Unit Types (Appendix C) 47
48. Minimum Design Data for Editing Utility (Company) Code
Unit Code
NERC Region
Date of commercial operation
Reaching 50% of its generator nameplate MW capacity
Turned over to dispatch (enters “active state”)
Nameplate rating of unit (permanent)
State location 48
49. Design Data Forms Forms are located in Appendix E
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. 49
50. Example of Design Data Form 50
51. 51
52. Why collect performance records? Collect generation of unit on a monthly basis.
Provide a secondary source of checking event data.
Allows analysis of fuels 52
53. Performance Report “05” Format (new)
More accurate with 2 decimal places for capacities, generation and hours.
Collects inactive hours (discussed later)
As of January 1, 2010, GADS only accepts the new format.
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54. Performance Records General Overview:
Provides summary of unit operation during a particular month of the year.
Actual Generation
Hours of operation, outage, etc.
Submitted quarterly for each month of the year.
Within 30 days after the end of the quarter 54
55. 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) 55
56. 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 (required)
Original Reports (0)
Additions or corrections (1, 2,…9)
Report all records to a performance report if you revise just one of the records. 56
57. Unit Generation Six data elements
Capacities and generation of the unit during the report period.
Can report both gross and net capacities.
Net is preferred
Missing Net or Gross capacities will be calculated! 57
58. 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
Power generated before auxiliaries 58
59. 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
Power generated after auxiliaries.
Can be negative if more aux than gross!
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60. Gas Turbine/Jet Capacities GT & Jets capacities do not remain as constant as fossil/nuclear units.
ISO standard for the unit (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 60
61. Effect of Ambient Temperature 61
62. Maximum and Dependable Capacity What is the difference betweenMaximum and Dependable?
GMC - GDC = Ambient Losses
NMC - NDC = Ambient Losses
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63. 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) 63
64. Missing Capacity Calculation! Factors are based on data reported to GADS in 1998 as follows: 64
65. 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 GDC is reported and the GDC = 50, then:
GDC = GMC = 50
NMC = GMC times (1 - factor)
NDC = GDC times (1 - factor)
NAG = GAG times (1 – factor) 65
66. 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! 66
67. Quick Quiz Question:
Suppose your utility only collects net generation numbers. What should you do with the gross generation fields? 67
68. 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. 68
69. Unit Loading Typical Unit Loading Characteristics
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70. Attempted & Actual Unit Starts Attempted Unit Starts
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
Unit actually synchronized to the grid 70
71. Attempted & Actual Unit Starts (cont.) 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.
The GADS program also accepts “0” in the attempts field if actual = 0 also. 71
72. Unit Time Information Service Hours (SH)
Number of hours synchronized to system
Reserve Shutdown Hours (RSH)
Available for load but not used (economic) 72
73. Unit Time Information (cont.) Pumping Hours
Hours the hydro turbine/generator operated as a pump/motor
Synchronous Condensing Hours
Unit operated in synchronous mode
Hydro, pumped storage, gas turbine, and jet engines
Available Hours (AH)
Sum of SH+RSH+Pumping Hours+ synchronous condensing hours 73
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75. Unit Time Information (cont.) Planned Outage Hours (POH)
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)
Requires the unit to be removed from service before the end of the next weekend (before Sunday 2400 hours)
Maintenance Outage Hours (MOH)
Outage deferred beyond the end of the next weekend (after Sunday 2400 hours).
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76. Unit Time Information (cont.) Extensions of Scheduled Outages (ME, PE)
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 OSW, then extended time is a forced outage.
ISO and power pools must be notified in advance of any extensions whether ME, PE, or U1. 76
77. Unit Time Information (cont.) Unavailable Hours (UAH)
Sum of POH+FOH+MOH+PE+ME
Period Hours or Active (PH)
Sum of Available + Unavailable Hours
Inactive Hours (IH)
The number of hours the unit is in the inactive state (Inactive Reserve, Mothballed, or Retired.)
Discussed later in detail. 77
78. Unit Time Information (cont.) Calendar Hours
Sum of Period Hours + Inactive Hours
For most cases, Period Hours = Calendar Hours 78
79. 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? 79
80. 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.
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. 80
81. 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%} 81
82. 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. It is best to round a fraction of an hour up then to round it down.
625.4 hours => 626 hours
Check the NMC of the unit. You can adjust it each month. 82
83. 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 83
84. Primary Fuel (cont.) Fuel Code (required)
Quantity Burned (optional)
Average Heat Content (optional)
% Ash (optional)
%Moisture (optional)
% Sulfur (optional)
% Alkalis (optional)
Grindability Index (coal only)/ % Vanadium and Phosphorous (oil only) - (optional)
Ash Softening Temperature (optional) 84
85. Fuel Codes 85
86. 86
87. 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? 87
88. Quick Quiz (cont.) Answer:
There is no such thing as a nuclear powered gas turbine! 88
89. 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? 89
90. Quick Quiz (cont.) Answer:
There is no derating!
NMC – NDC = 100 – 100 = 0 (zero) 90
91. 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? 91
92. Quick Quiz (cont.) Answer:
There is no derating!
NMC – NDC = 95 – 95 = 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) 92
93. 93
94. 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. 94
95. The “Ouch” Factor Non-IEEE or any other term
A description of what is the maximum information you can gather from a power generator before they yell “ouch!”
GADS is at the maximum Ouch Factor at this time. 95
96. Event Identification Record Code – the “07” uniquely identifies the data as an event 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) 96
97. 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 97
98. One Event for One Outage 98
99. 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? 99
100. 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
Hours of outage
Cause codes and event types 100
101. GADS is a DYNAMIC System 101
102. 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. 102
103. Event Identification (cont.) Report Revision Code – shows changes to the event record (required)
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
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104. Unit States 104
105. Unit States – Inactive 105
106. 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 106
107. 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. 107
108. 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. 108
109. 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. 109
110. Unit States – Active 110
111. Event Identification (cont.) Event Type (required -- 17 choices)
Two-character code describes the event (outage, derating, reserve shutdown, or noncurtailing). 111
112. 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! 112
113. From the Unit States Diagram 113
114. From the Unit States Diagram 114
115. Unit States – Active (cont.) Scheduled-type Outages
Planned Outage (PO)
Outage planned “Well in Advance” such as the annual unit overhaul.
Predetermined duration.
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)
If an outage occurs before Friday at 2400 hours, the above definition applies.
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.
If the outage can not be deferred, the outage shall be a forced event. 115
116. Unit States – Active (cont.) Scheduled-type Outages
Planned Extension (PE) – continuation of a planned outage.
Maintenance Extension (ME) – continuation of a maintenance outage. 116
117. 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 that 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. 117
118. 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: 01010000
End of Event: 01010001 118
119. Unit States – Active (cont.) Forced-type Outages
Immediate (U1) – requires immediate removal from service, another Outage State, or a Reserve Shutdown state. This type of outage usually results from immediate mechanical/electrical/hydraulic control systems trips and operator-initiated trips in response to unit alarms.
Delayed (U2) – not required immediate removal from service, but requires removal within six (6) hours. This type of outage can only occur while the unit is in service.
Postponed (U3) – postponed beyond six (6) hours, but requires removal from service before the end of the next weekend
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120. Unit States – Active (cont.) Forced-type Outages
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. 120
121. Example #1 – Simple Outage 121
122. Example #1 – Simple Outage 122
123. Scenario #1: FO or MO? There was a tube leak in the boiler 4 days before the scheduled PO. (Normal repair time 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? 123
124. Scenario #1: FO or MO? There was a tube leak in the boiler 4 days before the scheduled PO. (Normal repair time 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 to fix tube leak (U2) then change to PO. Why? 124
125. Scenario #1: FO or MO? There was a tube leak in the boiler 4 days before the scheduled PO. (Normal repair time 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! 125
126. Scenario #2: FO or MO? Vibration on unit’s ID Fan started on Thursday 10 a.m.
The unit could stay on line until the next Monday but dispatch says you can come off Friday morning. On Friday, the dispatch reviewed the request and allowed unit to come off for repairs.
What type of outage is this? 126
127. Scenario #2: FO or MO? Vibration on unit’s ID Fan started on Thursday 10 a.m.
The unit could stay on line until the next Monday but dispatch says you can come off Friday morning. On Friday, the dispatch reviewed the request and allowed unit to come off for repairs.
What type of outage is this?
Answer: MO. Why? 127
128. Scenario #2: FO or MO? Vibration on unit’s ID Fan started on Thursday 10 a.m.
The unit could stay on line until the next Monday but dispatch says you can come off Friday morning. On Friday, the dispatch reviewed the request 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. 128
129. Scenario #3: FO or MO? 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 GT would not be needed until the next Monday afternoon.
What type of outage is this?
129
130. Scenario #3: FO or MO? 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 GT would not be needed until the next Monday afternoon.
What type of outage is this?
Answer: FO. Why? 130
131. Scenario #3: FO or MO? 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 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. 131
132. Scenario #4: FO or RS? It’s Monday. Combined cycle had a HRSG tubeleak and must come off line now. It is 2x1 with no by-pass capabilities.
Dispatch said CC was not needed for remainder of week.
Management decided to repair the unit on regular maintenance time. Over the next 36 hours, the HRSG was repaired. Normal HRSG repairs take 12 hours of maintenance time.
What type of outage is this and for how long? 132
133. Scenario #4: FO or RS? It’s Monday. Combined cycle had a HRSG tube leak and must come off line now. It is 2x1 with no by-pass capabilities.
Dispatch said CC was not needed for remainder of week.
Management decided to repair the unit on regular maintenance time. Over the next 36 hours, the HRSG was repaired. 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 (CA). 133
134. Scenario #5: PE or FO? During 4 week PO, repairs on Electrostatic Precipitator (ESP) were more extensive then planned.
At the end of 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? 134
135. Scenario #5: PE or FO? During 4 week PO, repairs on Electrostatic Precipitator (ESP) were more extensive then planned.
At the end of 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: SE. Why? 135
136. Scenario #5: PE or FO? During 4 week PO, repairs on Electrostatic Precipitator (ESP) were more extensive then planned.
At the end of 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. 136
137. Scenario #6: ME or FO? During 4 week MO, mechanics discovered Startup BFP seals needed replacing. (not part of scope.)
At the end of 4 week, the SBPF work was not completed because of no parts on site. 12 hour delay in startup to complete work on SBFP.
What type of outage is the extra 12 hours?
137
138. Scenario #6: ME or FO? During 4 week MO, mechanics discovered Startup BFP seals needed replacing. (not part of scope.)
At the end of 4 week, the SBPF work was not completed because of no parts on site. 12 hour delay in startup to complete work on SBFP.
What type of outage is the extra 12 hours?
Answer: FO. Why?
138
139. Scenario #6: ME or FO? During 4 week MO, mechanics discovered Startup BFP seals needed replacing. (not part of scope.)
At the end of 4 week, the SBPF work was not completed because of no parts on site. 12 hour delay in startup to complete work on SBFP.
What type of outage is the extra 12 hours?
Answer: No part of original scope and delayed startup by 12 hours.
139
140. 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? 140
141. 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? 141
142. 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. 142
143. More Examples? 143
144. 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.
If a unit needs to come off and is not allowed to, more damage to the equipment and longer outages will be the result. (Investigation from Southern Co.) 144
145. 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 forced-type 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 145
146. 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. 146
147. 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 9998. 147
148. 148
149. Unit States (Deratings) What is a derate?
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.
An capacity is based on the capability of the unit, not on dispatch requirements.
More than one derate can occur at a time. 149
150. Unit States (Deratings) Report a derate or not?
If the derate is less than 2% NMC AND last less than 30 minutes, then it is optional whether you report it or not.
All other derates shall be reported!
Report a 1-hour derate with 1% reduction
Report a 15-minute derate with a 50% reduction. 150
151. Unit Capacity Levels Deratings
Ambient-related Losses are not reported as deratings - report on Performance Record (NMC-NDC)
System Dispatch requirements are not reported 151
152. 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.
152
153. 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). 153
154. Unit States – Active (cont.) Scheduled Deratings (cont.)
Planned Extension (DP) – continuation of a planned derate.
Maintenance Extension (DM) – continuation of a maintenance derate. 154
155. 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. 155
156. Unit Capacity Levels 156
157. Example #2 – Simple Derating 157
158. Example #2 – Simple Derating 158
159. Unit Deratings Deratings that vary in magnitude
New event for each change in capacity or,
Average the capacity over the full derating time. 159
160. Unit Deratings Overlapping Deratings
All deratings are additive unless shadowed by an outage or larger derating.
Shadowed derating 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. 160
161. Example #3 - Overlapping Deratings Second Starts & Ends Before First (G-3A) 161
162. Example #3 - Overlapping Deratings Second Starts & Ends Before First (G-3A) 162
163. 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. 163
164. Example #4 - Overlapping Derating(2nd is Shadowed by the 1st) (G-3B) 164
165. Example #4 - Overlapping Derating (1st is Shadowed by the 2nd) with Dominant Code 165
166. Dominant Derating Code 166
167. Dominant Derating Code (cont.) How do you know if a derating is dominant?
If you’re not sure, ask!
Control room operator
Plant engineer
If you don’t mark it dominant, the software will assume it is additive. That can result in inaccurate reporting.
167
168. 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. 168
169. Dominant Derating Code (cont.) 169
170. Dominant Derating Code (cont.) 170
171. Dominant Derating Code (cont.) 171
172. Dominant Derating Code (cont.) 172
173. 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. 173
174. 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. 174
175. 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.
175
176. 176
177. Other Unit States Reserve Shutdown – unit not synchronized but ready for startup and load as required.
Noncurtailing – 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? 177
178. 178
179. Event Magnitude Impact of the event on the unit
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! 179
180. Unit Capacity Levels 180
181. 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 … 181
182. 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! 182
183. 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! 183
184. 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 184
185. 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 185
186. 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. 186
187. Event Transitions (cont.) 187
188. 188
189. Quick Quiz 189
190. 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? 190
191. Quick Quiz (cont.) Answer:
Change the U2 to an SF 191
192. 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? 192
193. Quick Quiz (cont.) Answer:
No. Why?
Standard operating procedure. By NERC’s standards, it is not a derate. 193
194. 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? 194
195. Quick Quiz (cont.) Answer:
No! All ramp up and safety checks are all with the normal time for the unit. 195
196. 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? 196
197. 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. 197
198. 198
199. Primary Event Cause Details of the primary cause of event
What caused the outage/derate?
May not always be the root cause 199
200. Primary Event Cause Described by using cause code
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.
Cause codes for fossil-steam units only
Cause codes for hydro units only 200
201. Set of Cause Codes for Each Unit Type Fossil
Fluidized Bed Fossil
Nuclear
Diesel
Hydro/Pumped Storage Gas Turbine
Jet Engine
Combined Cycle & Co-generator
Geothermal 201 We have 11 choices of units in pc-GAR. Here is a list of the choices.
Please note that we cannot combine two of these groups such as fossil and gas turbines. We do not want people to mix two different technologies.We have 11 choices of units in pc-GAR. Here is a list of the choices.
Please note that we cannot combine two of these groups such as fossil and gas turbines. We do not want people to mix two different technologies.
202. Set of Cause Codes for Each Unit Type Example of two names, different units:
Fossil-steam
0580 - Desuperheater/attemperator piping
0590 - Desuperheater/attemperator valves
Combined cycle
6140 - HP Desuperheater/attemperator piping - Greater than 600 PSIG.
6141 - HP Desuperheater/attemperator valves
202
203. Cause Codes for Internal Economics Document specific demand periods verses “average” differences for a month.
Want to calculate EAF and NCF differences for any period of time.
NOT REPORTED TO GADS!
20 cause codes (9180 to 9199) set up. 203
204. What is Amplification Code? 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)
This is voluntary but important. 204
205. 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 205
206. 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”
206
207. Event Contribution Codes Contribution Codes
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.
3 Work done during the event – worked on during event but did not initiate event.
5 After startup, delayed unit from reaching load point
Note: No codes 6 or 7 as of January 1, 1996 207
208. 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. 208
209. Primary Event Cause (cont.) Time: Work Started/Time: Work Ended (optional)
Uses 24 hour clock and looks at event start & end dates & times.
Problem Alert (optional)
Man Hours Worked (optional)
Verbal Description (optional)
Most helpful information is in the verbal descriptions IF they are completed correctly. 209
210. Types of Failures (III-34, App. H) Erosion
Corrosion
Electrical
Electronic
Mechanical
Hydraulic
Instruments
Operational
210
211. Typical Contributing Factors 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 211
212. Typical Corrective Actions Recalibrate
Adjust
Temporary Repair
Temporary Bypass
Redesign
Modify
Repair Part(s) Replace Part(s)
Repair Component(s)
Reseal
Repack
Request License Revision 212
213. Compare the difference ... Cause Code 1000
U1 Outage
“The unit was brought off line due to water wall leak” Cause Code 1000
U1 Outage
“Leak. 3 tubes eroded from stuck soot blower. Replaced tubes, soot blower lance.” 213
214. Additional Cause of Event Same layout as primary outage causes
Used to report factors contributing to the cause of event, additional work, factors affecting startup/rampdown
Up to 46 additional repair records allowed 214
215. Expanded Data Reporting (III-36-38, App. H) 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) 215
216. 216
217. 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? 217
218. Quick Quiz (cont.) Answer:
1800 - Major Boiler overhaul
more than 720 hours
1801 - Minor Boiler overhaul
720 hours or less 218
219. 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? 219
220. Quick Quiz (cont.) Answer:
Major Turbine overhaul
Cause Code 4400
Contribution Code 1
High-Pressure Turbine reblading
Cause Code 4012
Contribution Code 1 220
221. Quick Quiz (cont.) Question:
The following non-curtailing event was reported on a 300 MW unit:
Started January 3 @ 1300
Ended January 12 @ 0150
Cause Code 3410 (Boiler Feed Pump)
Gross Available Capacity: *
Net Available Capacity: 234 MW
Is everything okay with this description? 221
222. 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. 222
223. 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? 223
224. 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-6 224
225. Quick Quiz (cont.) Question:
Riverglenn #1 experienced a FO as follows:
Start date/time: October 3 @ 1545
End date/time: October 3 @ 1321
GAC:
NAC:
Cause Code: 1455
Description: ID fan vibration, fly ash buildup on blades
Is this event reported correctly? 225
226. Quick Quiz (cont.) Answer:
The start time of the event is after the end time.
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 1455. 226
227. 227
228. 228
229. The “Standard” ANSI/IEEE Standard, “Definitions for Use in Reporting Electric Generating Unit Reliability, Availability, and Productivity”
Approved September 19, 1985
Renewal completed in 2006
Many parts taken from EEI standard.
Originally, designed for base-loaded units only! Now, all types of unit operation! 229
230. Unit States 230
231. From the Unit State Chart … 231
232. From the Unit State Chart … 232
233. Please note … Unplanned and scheduled numbers ARE NOT ADDITIVE!!!!
Why?
Maintenance outages in both numbers.
Use unplanned or scheduled for your uses but don’t compare them. 233
234. Two Classes of Equations Time-based
All events
Without Outside Management Control (OMC)
Capacity- or Energy-based
All events
Without Outside Management Control (OMC)
234
235. Time-based Equations Used by industry and GADS for many years.
All units are equal no matter its MW size because equation is based on time, not the capacity of the unit or units. 235
236. Capacity-based Equations Used mostly in-house by industry. Used in one GADS report for many years but not is many.
All units are not equal because equation is based on capacity (not time) of the units.
In this example, the 500MW unit has 10 times the impact on the combination of the 50 & 500 MW units because it is 10 times bigger. 236
237. Outside Management Control (OMC) 237
238. Outside Management Control (OMC) There are a number of outage causes that may prevent the energy coming from a power generating plant from reaching the customer. Some causes are due to the plant operation and equipment while others are outside plant management control (OMC).
GADS needs to track all outages but wants to give some credit for OMC events. 238
239. What are OMC Events? Grid connection or substation failure.
Acts of nature such as ice storms, tornados, winds, lightning, etc
Acts of terrors or transmission operating/repair errors
Special environmental limitations such as low cooling pond level, or water intake restrictions 239
240. What are OMC Events? Lack of fuels
water from rivers or lakes, coal mines, gas lines, etc
BUT NOT operator elected to contract for fuels where the fuel (for example, natural gas) can be interrupted.
Labor strikes
BUT NOT direct plant management grievances 240
241. More Information? Appendix F – Performance Indexes and Equations
Appendix K for description of “Outside Management Control” and list of cause codes relating to the equation. 241
242. Time-based Indices Equivalent Availability Factor (EAF)
Equivalent Unavailability Factor (EUF)
Scheduled Outage Factor (SOF)
Forced Outage Factor (FOF)
Maintenance Outage Factor (MOF)
Planned Outage Factor (POF) 242
243. Time-based Indices Energy Factors
Net Capacity Factor (NCF)
Net Output Factor (NOF)
Rates
Forced Outage Rate (FOR)
Equivalent Forced Outage Rate (EFOR)
Equivalent Forced Outage Rate – Demand (EFORd)
243
244. 244
245. Equivalent Availability Factor (EAF) By Definition:
The fraction of net maximum generation that could be provided after all types of outages and deratings (including seasonal deratings) are taken into account.
Measures percent of maximum generation available over time.
Not affected by load following
The higher the EAF, the better.
Derates reduce EAF using Equivalent Derated Hours. 245
246. What is meant by “Equivalent Derated Hours?” This is a method of converting deratings into full outages
The product of the Derated Hours and the size of reduction, divided by NMC
100 MW derate for 4 hours is the same loss as 400 MW outage for 1 hour.
100MWx4hours = 400MWx1hour 246
247. Equivalent Availability Factor (EAF) 247
248. Equivalent Unavailability Factor (EUF) Compliment of EAF
EUF = 100% - EAF
Percent of time the unit is out of service or restricted from full-load operation due to forced, maintenance & planned outages and deratings.
The lower the EUF the better. 248
249. Scheduled Outage Factor (SOF) By Definition:
The percent of time during a specific period that a unit is out of service due to either planned or maintenance outages.
Outages are scheduled.
PO – “Well in Advance”
MO - Beyond the next weekend.
A measure of the unit’s unavailability due to planned or maintenance outages.
The lower the SOF, the better.
249
250. Scheduled Outage Factor (SOF) 250
251. Other Outage Factors 251
252. Forced Outage Factor (FOF) By Definition:
The percent of time during a specific period that a unit is out of service due to forced outages.
Outages are not scheduled and occur before the next weekend.
A measure of the unit’s unavailability due to forced outages over a specific period of time.
The lower the FOF, the better.
252
253. Forced Outage Factor (FOF) 253
254. Net Capacity Factor (NCF) By Definition:
Measures the actual energy generated as a fraction of the maximum possible energy it could have generated at maximum operating capacity.
Shows how much the unit was used over the period of time.
The energy produced may be outside the operators control due to dispatch.
The higher the NCF, the more the unit was used to generate power (moving to “base-load”). 254
255. Net Capacity Factor (NCF) 255
256. Net Output Factor (NOF) By Definition:
Measures the output of a generating unit as a function of the number of hours it was in service (synchronized to the grid)
How “hard” was the unit pushed.
The energy produced may be outside the operators control due to dispatch.
The higher the NOF, the higher the loading of the unit when on-line.
256
257. Net Output Factor (NOF) 257
258. Comparing NCF and NOF 258
259. Comparing AF/EAF/NCF/NOF 259
260. What can you learn from the numbers below? 260
261. Meeting Demand in Real Time 261
262. What can you learn from the numbers below? 262
263. 263
264. Forced Outage Rate By Definition:
The percent of scheduled operating time that a unit is out of service due to unexpected problems or failures.
Measures the reliability of a unit during scheduled operation
Sensitive to service time
(reserve shutdowns and scheduled outage influence it)
Best used to compare similar loads:
base load vs. base load
cycling vs. cycling
The lower the FOR, the better.
264
265. Forced Outage Rate 265
266. Equivalent Forced Outage Rate By Definition:
The percent of scheduled operating time that a unit is out of service due to unexpected problems or failures AND cannot reach full capability due to forced component or equipment failures
The probability that a unit will not meet its demanded generation requirements.
Good measure of reliability
The lower the EFOR, the better. 266
267. Equivalent Forced Outage Rate 267
268. Equivalent Forced Outage Rate 268
269. Equivalent Forced Outage Rate – Demand (EFORd) Markov equation developed in 1970’s
Used by the industry for many years
PJM Interconnection (20 years)
Similar to that used by the Canadian Electricity Association (20 years)
Being use by the CEA, PJM, New York ISO, ISO New England, and California ISO. 269
270. Equivalent Forced Outage Rate – Demand (EFORd) Interpretation:
The probability that a unit will not meet its demand periods for generating requirements.
Best measure of reliability for all loading types (base, cycling, peaking, etc.)
Best measure of reliability for all unit types (fossil, nuclear, gas turbines, diesels, etc.)
For demand period measures and not for the full 24-hour clock.
The lower the EFORd, the better.
270
271. Equivalent Forced Outage Rate – Demand (EFORd) 271
272. EFORd Equation: 272
273. Example of EFORd vs. EFOR 273
274. Example of EFORd vs. EFOR 274
275. Limiting Conditions for EFORd 275
276. What can you learn from the numbers below? 276
277. How to Avoid Misleading EFORd Use a large population of units.
Use a long period of time if analyzing a single unit (at least one year.) Monthly FORd or EFORd may work on some months but not all.
Check data! If Service Hours is zero, increase population or period so it is not zero.
277
278. EAF + EFOR = 100%? 278
279. Other Equations in IEEE 762 279
280. Other Equations in IEEE 762 Equivalent Maintenance Outage Factor
Equivalent Planned Outage Factor
Equivalent Forced Outage Factor 280
281. Other Equations in IEEE 762 Equivalent Maintenance Outage Rate
Equivalent Planned Outage Rate
Equivalent Forced Outage Rate 281
282. 282
283. Comparing EAF, WEAF, XEAF, etc. 283
284. Comparing EAF, WEAF, XEAF, etc. 284
285. Comparing EAF, WEAF, XEAF, etc. 285
286. Comparing EAF, WEAF, XEAF Time-based is simple to understand and calculate. Good method for units of the same MW size.
Capacity-based is more complicated to calculate but provides a more accurate view of total system capabilities, especially for units of different MW sizes
OMC-based allows power stations a fair grade on performance by removing outside influences on production.
286
287. 287
288. 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.
288
289. Commercial Availability 289
290. 290
291. Beware of Statistical Scatter Averages or means can be misleading
Sample should be at least 30
Also use median, mode, standard deviation, range
Beware of bimodal distributions
Separate unique populations
Tools
pc-GAR, SAS, scatter diagrams, etc.
291
292. Weighted Equivalent Availability Factor 292
293. Weighted Equivalent Availability Factor 293
294. WEAF and Age of Fossil UnitsAll Sizes and Fuels 294
295. 295
296. Data pooling means collecting the data of several units and combining them into one number
Average EUF (or CUF), EFORd, NCF, etc
IEEE Committee on Probabilities and Applications reviewed methods
Summarize hours first then divide by number in sample. Then put results in equation.
DO NOT average factors, rates, etc. Words About Pooling Data 296
297. Words About Pooling Data 297
298. GADS Standard for EFORd Will follow IEEE recommendation as shown in Appendix F, Notes 1 and 2.
Will use Method 2 for calculating EFORd and FORd in all GADS publications and pc-GAR.
Consistency – all other GADS equations sum hours in both the denominator and numerator before division.
Allow calculations of smaller groups. By allowing sums, smaller groups of units can be used to calculate EFORd without experiencing the divide by zero problem (see Note #2 for Appendix F). 298
299. Pooling Time-based Statistics Equivalent Maintenance Outage Factor
Equivalent Planned Outage Factor
Equivalent Forced Outage Factor 299
300. Pooling Weighted Statistics Weighted Equivalent Maintenance Outage Factor
Weighted Equivalent Planned Outage Factor
Weighted Equivalent Forced Outage Factor
300
301. 301
302. GADS and the World Energy Council GADS is involved with the World Energy Council (WEC) and its Performance of Generating Plant (PGP) subcommittee.
Teaching workshops
Providing software
Wanting to create a WEC-GADS database and a “WEC pc-GAR”
Continue to explore best way to collect unit specific data on fossil units worldwide for WEC pc-GAR software. 302
303. Continuing Projects Adding wind generators to GADS
Working group formed to determine design, event, cause codes, etc. for data collection.
Discussion of wind data collection is on Thursday at 8:00 a.m.
303
304. Continuing Projects Adding wind generators to GADS
Started database on concentrated solar and PV earlier this year. Still in the works… 304
305. Exchange data with Europe and CEA Exchange data with Europe and the Canadian Electricity Association (CEA)
Continue correspondence with the International Atomic Power Agency (IAEA) 305
306. 306
307. Design Data Time Stamping Tracking changes in plants with time.
Addition/removal of equipment like bag houses, mechanical scrubbers, etc.
Upgrading or changing equipment like pumps, fans, etc.
Will be sent out to each reporter by the end of November this year (if not sooner). 307
308. 308
309. Data Transmittal Tools 309
310. Data Release Guidelines Operating companies have access to own data only.
Manufacturers have access to equipment they manufactured only.
Other organizations do not have access to unit-specific data unless they receive written permission from the generating company.
In grouped reports, no report is provided if less than 7 units from 3 operating companies. 310
311. Access to pc-GAR If you are a generating company in North America and report your GADS data to NERC, you can purchase pc-GAR.
If you are a generating company in North America and do not report your GADS data to NERC, you cannot purchase pc-GAR.
If you are a generating company outside North America and either do or do not report GADS data to GADS, you can purchase pc-GAR. 311
312. 312
