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G. Michael CurleyManager of GADS ServicesOctober 27-29, 2010
NERC GADS 101NERC GADS 101Data Reporting WorkshopData Reporting Workshop
GADS Services Staff
• Mike Curley – Manager of GADS Services
• Joanne Rura – GADS Services Coordinator
• Ronald Niebo – Reliability Assessment and Performance Analysis Coordinator
Please stand and introduce yourselves
• Your name, company, and experience with GADS
WelcomeWelcome
2
Overview of Attendees at this ConferenceOverview of Attendees at this Conference
Representatives of:
• Generating companies (IOU, IPPs, Government, etc)
• Consultants
• Insurance
• ISOs
3
What’s in the folder?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 drive4
What’s on the flash drive?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
AgendaAgenda
Introduction and welcoming remarks
• What is NERC?
• What is GADS?
Fundamentals on the three GADS Databases
DesignWhat makes up the design database?
Event What are the elements of the event database?
PerformanceWhat are the elements of the performance database?
6
Agenda (cont.)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
NERC BackgroundNERC 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
Energy Policy Act of 2005Energy 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
Energy Policy Act of 2005Energy 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
About NERCAbout NERC
Develop & enforce reliability standards
Analyze system outages and near-misses & recommend improved practices
Assess current and future reliability
International regulatory authority for electric reliability in North America
12
Meeting Demand in Real TimeMeeting Demand in Real Time
Typical Daily Demand Curve
Base Load
Intermediate Load
Peak Load
Operating Reserves
Energy: Electricity Produced over Time
Capacity: Instantaneous measure of electricity available at peak
13
About NERC: Regional Entities (RE)About 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
14
What does NERC do?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
One of the first orders of business…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
Work now…Work now…
Marry the transmission to the generation databases, using Section 1600 of the Rules of Procedure.
17
GADS Task ForceGADS 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
Rules of Procedure: Section 1600Rules of Procedure: Section 1600OverviewOverview
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
Rules of Procedure: Section 1600Rules of Procedure: Section 1600Request DetailsRequest 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
NERC Approval CommitteesActingSubgroup
Rules of Procedure: Section 1600Rules of Procedure: Section 1600ProcedureProcedure
Draft Data
Request
Submit Data
Request to DCS
Submit Data
Request to PC
Not Approved
Not Approved
SubmitData
Request
FERC Comment Period
File DataRequest
(21 Days)
Public Comment Period
Post DataRequest
(45 Days)
Collect,Respond, &
PostComments
FinalizeData
Request
NERC Board of Trustees
SubmitFinal Data
Request
Data RuleIn Effect
Affected Parties
Appeal(30 Days)
Approved
Not Approved
No
Ap
pe
al
21
Rules of Procedure: Section 1600Rules of Procedure: Section 1600LimitationsLimitations
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
What if a GO doesn’t comply?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.
23
What if a GO doesn’t comply?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.
24
What if a GO doesn’t comply?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
What if a GO doesn’t comply?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.
26
What if a GO doesn’t comply?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
GADS vs. ISO Data Collection RulesGADS 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
More information?More information?
Please visit our website: www.nerc.com
Most information is open to the public.
29
What is GADS?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
Example – Benchmarking – Distributions Example – Benchmarking – Distributions
[Fossil-steam units 200-400MW; Coal fuel; 6,500+ Service Hours/Yr.; 2005-2009; (79 units from 73 companies)] 33
Example – Benchmarking – Top ProblemsExample – Benchmarking – Top Problems
[Fossil-steam units 200-400MW; Coal fuel; 6,500+ Service Hours/Yr.; 2005-2009; (79 units from 73 companies)] 34
What is meant by “Availability?”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
Monitor the PresentMonitor the Present
GADS
Generator “B”
Generator “A”
Generator “C”
Generator “D”
Generator “E”
5,800+ generating units including 2 international affiliates.
36
International GADS UsersInternational GADS Users
Malaysia *
Ireland *
Brazil *
India *
Peoples Republic of China
Spain
New Zealand
South Korea
Parts of S. America
* Are or soon will be reporting outage data to GADS.
37
GADS 2009 Data ReportingGADS 2009 Data Reporting
3000
3500
4000
4500
5000
5500
6000
1990 1992 1994 1996 1998 2000 2002 2004 2006 2008
5,874 units reported in 2009, 0.9% increase in thenumber of units reporting over 2008!
38
Why GADS?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
Why GADS?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
Why GADS?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
41
The GADS DatabasesThe 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.
44
Why collect design data?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
Unit Types (Appendix C)Unit Types (Appendix C)
Unit Type Coding Series
Fossil (Steam)(use 600-649 if additional numbers are needed)
100-199
Nuclear 200-299
Combustion Turbines(Use 700-799 if additional numbers are needed)
300-399
Diesel Engines 499-499
Hydro/Pumped Storage(Use 900-999 if additional numbers are needed)
500-599
Fluidized Bed Combustion 650-699
Miscellaneous(Multi-Boiler/Multi-Turbine, Geothermal, Combined Cycle Block, etc.)
800-899
47
Minimum Design Data for EditingMinimum 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
Design Data FormsDesign 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
Why collect performance records?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
Performance ReportPerformance 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.
53
Performance RecordsPerformance 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
Unit IdentificationUnit 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
Unit Identification (cont.)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
Unit GenerationUnit 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
Unit Generation (cont.)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
Unit Generation (cont.)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!
59
Gas Turbine/Jet CapacitiesGas 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
Maximum and Dependable CapacityMaximum and Dependable Capacity
What is the difference betweenMaximum and Dependable?
• GMC - GDC = Ambient Losses
• NMC - NDC = Ambient Losses
62
Missing Capacity Calculation!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
Missing Capacity Calculation!Missing Capacity Calculation!
Factors are based on data reported to GADS in 1998 as follows:
Unit Type Difference
Fossil, Nuclear, and Fluidized Bed: 5.0% difference between gross and net values
Gas Turbine/Jet Engine: 2.0% difference between gross and net values
Diesel: No difference between gross and net values
Hydro/Pumped Storage: 2.0% difference between gross and net values
Miscellaneous: 4.0% difference between gross and net values
64
Missing Capacity Calculation!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
Missing Capacity Calculation!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
Quick QuizQuick Quiz
Question:
Suppose your utility only collects net generation numbers. What should you do with the gross generation fields?
67
Quick Quiz (cont.)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
Unit LoadingUnit Loading
Typical Unit Loading Characteristics
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)
69
Attempted & Actual Unit StartsAttempted & 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 grid70
Attempted & Actual Unit Starts (cont.)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
Unit Time InformationUnit Time Information
Service Hours (SH)
• Number of hours synchronized to system
Reserve Shutdown Hours (RSH)
• Available for load but not used (economic)
72
Unit Time Information (cont.)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
Unit Time Information (cont.)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).
75
Unit Time Information (cont.)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
Unit Time Information (cont.)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
Unit Time Information (cont.)Unit Time Information (cont.)
Calendar Hours
• Sum of Period Hours + Inactive Hours
• For most cases, Period Hours = Calendar Hours
78
Quick QuizQuick 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
Quick Quiz (cont.)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
Quick Quiz (cont.)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
Quick Quiz (cont.)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
Primary FuelPrimary 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
Primary Fuel (cont.)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
Fuel CodesFuel 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.)
Fuel Codes
85
Quick QuizQuick 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
Quick Quiz (cont.)Quick Quiz (cont.)
Answer:
There is no such thing as a nuclear powered gas turbine!
88
Quick Quiz (cont.)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
Quick Quiz (cont.)Quick Quiz (cont.)
Answer:
There is no derating!
• NMC – NDC = 100 – 100 = 0 (zero)
90
Quick Quiz (cont.)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
Quick Quiz (cont.)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
Why Collect Event Records?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
The “Ouch” FactorThe “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
Event IdentificationEvent 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
Event Identification (cont.)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
One Event for One OutageOne Event for One Outage
Month 1 Month 2 Month 3
Event 1 Event 1 Event 1
Event 1
98
Quick QuizQuick 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
Quick Quiz (cont.)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
GADS is a GADS is a DYNAMICDYNAMIC SystemSystem
Make as many changes as you want,
as many times as you want,
whenever you want.
101
Report Year-to-date!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
Event Identification (cont.)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
• Active103
Unit States – Inactive (cont.)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
Unit States – Inactive (cont.)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
Unit States – Inactive (cont.)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
Unit States – Inactive (cont.)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
Event Identification (cont.)Event Identification (cont.)
Event Type (required -- 17 choices)
• Two-character code describes the event (outage, derating, reserve shutdown, or noncurtailing).
EVENT TYPES
OUTAGES DERATINGS
PO – Planned PD – Planned
PE – Planned Extension DP – Planned Extension
MO – Maintenance D4 – Maintenance
ME – Maintenance Extension DM – Maintenance Extension
SF – Startup Failure D1 – Forced - Immediate
U1 – Forced - Immediate D2 – Forced - Delayed
U2 – Forced - Delayed D3 – Forced - Postponed
U3 – Forced Postponed
RS – Reserve Shutdown
NC – Non Curtailing
111
Unit States – Active (cont.)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
From the Unit States DiagramFrom the Unit States Diagram
“Unplanned”
Forced + Maintenance + Planned
113
From the Unit States DiagramFrom the Unit States Diagram
Forced + Maintenance + Planned
“Scheduled”
114
Unit States – Active (cont.)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
Unit States – Active (cont.)Unit States – Active (cont.)
Scheduled-type Outages
• Planned Extension (PE) – continuation of a planned outage.
• Maintenance Extension (ME) – continuation of a maintenance outage.
116
Unit States – Active (cont.)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
PE or ME on January 1 at 00:00PE 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
Unit States – Active (cont.)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 119
Unit States – Active (cont.)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
Example #1 – Simple OutageExample #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.
121
Example #1 – Simple OutageExample #1 – Simple Outage
0
100
200
300
400
500
600
700
0 1 2 3 4 5 6
Jan 3 @ 0430 Jan 8 @ 1700
Forced Outage CC 4240
Capacity (MW)
122
Scenario #1: FO or MO?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
Scenario #1: FO or MO?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
Scenario #1: FO or MO?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
Scenario #2: FO or MO?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
Scenario #2: FO or MO?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
Scenario #2: FO or MO?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
Scenario #3: FO or MO? 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
Scenario #3: FO or MO? 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
Scenario #3: FO or MO? 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
Scenario #4: FO or RS? 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
Scenario #4: FO or RS? 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
Scenario #5: PE or FO?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
Scenario #5: PE or FO?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
Scenario #5: PE or FO?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
Scenario #6: ME or FO?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
Scenario #6: ME or FO?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
Scenario #6: ME or FO?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
Scenario #7: PO or FO?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
Scenario #7: PO or FO?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
Scenario #7: PO or FO?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
More Examples?More Examples?
Appendix G – Examples and Recommended Methods
Reporting Outages to the Generating AvailabilityData System (GADS)
143
A Word of Experience …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
Testing Following OutagesTesting 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
Black Start TestingBlack 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
Black Start Testing (cont.)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
Unit States (Deratings)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
Unit States (Deratings)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
Unit Capacity LevelsUnit Capacity Levels
Deratings
• Ambient-related Losses are not reported as deratings - report on Performance Record (NMC-NDC)
• System Dispatch requirements are not reported
151
Unit States – ActiveUnit 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
Unit States – Active (cont.)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
Unit States – Active (cont.)Unit States – Active (cont.)
Scheduled Deratings (cont.)
• Planned Extension (DP) – continuation of a planned derate.
• Maintenance Extension (DM) – continuation of a maintenance derate.
154
Unit States – Active (cont.)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
Unit Capacity LevelsUnit Capacity Levels
Maximum Capacity
Seasonal Derating = Maximum Capacity - Dependable Capacity
Dependable Capacity
Basic Planned DeratingPlannedDerating Extended Planned Derating
Unit Derating= D 1
D 2 UnplannedDerating
D 3
Maintenance
Available Capacity
Note: All capacity and deratings are to be expressed on either gross or net basis.
Dependable Capacity - Available capacity
156
Example #2 – Simple DeratingExample #2 – 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.
157
Example #2 – Simple DeratingExample #2 – Simple Derating
0
100
200
300
400
500
600
700
0 1 2 3 4 5 6
Jan 10 @ 0800 Jan 11 @1600
Derating
158
Unit DeratingsUnit Deratings
Deratings that vary in magnitude
• New event for each change in capacity or,
• Average the capacity over the full derating time.
159
Unit Deratings 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
Example #3 - Overlapping Deratings Example #3 - Overlapping Deratings Second Starts & Ends Before First (G-3A)Second Starts & Ends Before First (G-3A)
Event Description:
Riverglenn #1 had an immediate 100 MW derating onMarch 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.
161
Example #3 - Overlapping Deratings Example #3 - Overlapping Deratings Second Starts & Ends Before First (G-3A)Second Starts & Ends Before First (G-3A)
0
100
200
300
400
500
600
700
0 1 2 3 4 5 6
3/9@:0845 3/9@1800
Capacity (MW)
Forced Derating CC 0250
D1 CC0320
3/9@1000 3/9@1100
162
Dominant Derating CodeDominant 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
Example #4 - Overlapping DeratingExample #4 - Overlapping Derating(2nd is Shadowed by the 1st) (G-3B)(2nd is Shadowed by the 1st) (G-3B)
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. 164
Example #4 - Overlapping Derating Example #4 - Overlapping Derating (1st is Shadowed by the 2nd) with Dominant Code(1st is Shadowed by the 2nd) with Dominant Code
0
100
200
300
400
500
600
700
0 1 2 3 4 5 6
7/3@1430 7/23@1145
Capacity (MW)D4 CC 3112
D1 CC 3410
7/19@1115 7/19@1200
165
Dominant Derating CodeDominant Derating Code
300
400
500
600
700Capacity (MW)
D4 CC 3112
D1 CC3410
300
400
500
600
700Capacity (MW)
D4 CC 3112
D1 CC3410
Event #1 Event #2
Event #1 Event #3
Event #2
Without Dominant Derating Code
With Dominant Derating Code
3 events to cover 2 incidents
2 events to cover 2 incidents166
Dominant Derating Code (cont.)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
Dominant Derating Code (cont.)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
Dominant Derating Code (cont.)Dominant Derating Code (cont.)
Normal DeratingsNormal Deratings
Event 1
Event 2
169
Dominant Derating Code (cont.)Dominant Derating Code (cont.)
Single Dominant DeratingSingle Dominant Derating
DominantDerating –Event 3
170
Dominant Derating Code (cont.)Dominant Derating Code (cont.)
Overlapping Dominant DeratingsOverlapping Dominant Deratings
DominantDerating –Event 3
DominantDerating –Event 4
Dominant Derating 3 SHADOWS portion of Event 4 171
Dominant Derating Code (cont.)Dominant Derating Code (cont.)
Overlapping Dominant Deratings by Virtue of LossOverlapping Dominant Deratings by Virtue of Loss
Derating –Event 4 takes the dominant position.
DominantDerating –Event 3
Derating –Event 4 172
Dominant Derating Code (cont.)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
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
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
Other Unit StatesOther 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
Event MagnitudeEvent 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
Unit Capacity LevelsUnit Capacity Levels
Maximum Capacity
Seasonal Derating = Maximum Capacity - Dependable Capacity
Dependable Capacity
Basic Planned DeratingPlannedDerating Extended Planned Derating
Unit Derating= D 1
D 2 UnplannedDerating
D 3
Maintenance
Available Capacity
Note: All capacity and deratings are to be expressed on either gross or net basis.
Dependable Capacity - Available capacity
180
Missing Capacity Calculation!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
Missing Capacity Calculation!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
Event Magnitude (cont.)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
Event Magnitude (cont.)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
Using the 24-hour ClockUsing 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
Event Transitions (Page III-24)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
Event Transitions (cont.)Event Transitions (cont.)
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
Allowable Event Type Changes
187
Quick QuizQuick 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?
189
Quick Quiz (cont.)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
Quick Quiz (cont.)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
Quick Quiz (cont.)Quick Quiz (cont.)
Answer:
No. Why?
Standard operating procedure. By NERC’s standards, it is not a derate.
193
Quick Quiz (cont.)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
Quick Quiz (cont.)Quick Quiz (cont.)
Answer:
No! All ramp up and safety checks are all with the normal time for the unit.
195
Quick Quiz (cont.)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
Quick Quiz (cont.)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
Primary Event CausePrimary Event Cause
Details of the primary cause of event
• What caused the outage/derate?
• May not always be the root cause
199
Primary Event CausePrimary 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
Set of Cause Codes for Each Unit TypeSet 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
Set of Cause Codes for Each Unit TypeSet 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
Cause Codes for Internal EconomicsCause 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
What is Amplification Code?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
Example of Amplification CodeExample of Amplification Code
C0 = Cleaning
E0 = Emission/environmental restriction
F0 = Fouling
45 = Explosion
53 = Inspection, license, insurance
54 = Leakage
P0 = Personnel error
R0 = Fire205
Example of Amplification CodeExample 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
Event Contribution CodesEvent Contribution Codes
Contribution Codes1 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
Event Contribution Codes (cont.)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
Primary Event Cause (cont.)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
Types of Failures (III-34, App. H)Types of Failures (III-34, App. H)
Erosion
Corrosion
Electrical
Electronic
Mechanical
Hydraulic
Instruments
Operational
(Same as Amplification Codes)
210
Typical Contributing FactorsTypical 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
Typical Corrective ActionsTypical 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
Method 2
Compare the difference ...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.”
Method 1
213
Additional Cause of EventAdditional 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
Expanded Data Reporting Expanded Data Reporting (III-36-38, App. H) (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
Quick QuizQuick 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
Quick Quiz (cont.)Quick Quiz (cont.)
Answer:
1800 - Major Boiler overhaul
• more than 720 hours
1801 - Minor Boiler overhaul
• 720 hours or less
218
Quick Quiz (cont.)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
Quick Quiz (cont.)Quick Quiz (cont.)
Answer:
Major Turbine overhaul
• Cause Code 4400
• Contribution Code 1
High-Pressure Turbine reblading
• Cause Code 4012
• Contribution Code 1
220
Quick Quiz (cont.)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
Quick Quiz (cont.)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
Quick Quiz (cont.)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
Quick Quiz (cont.)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
Quick Quiz (cont.)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
Quick Quiz (cont.)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
Lord Keyes said, “If you can’t measure it, then you can’t improve it.”
The reason we collect information on the power plants is to measure it’s performance and improve it as needed.
228
The “Standard”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
From the Unit State Chart …From the Unit State Chart …
“Unplanned” – corrective action
Forced + Maintenance + Planned
231
From the Unit State Chart …From the Unit State Chart …
Forced + Maintenance + Planned
“Scheduled” - preventive
232
Please note …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
Two Classes of EquationsTwo Classes of Equations
1. Time-based
• All events
• Without Outside Management Control (OMC)
2. Capacity- or Energy-based
• All events
• Without Outside Management Control (OMC)
234
Time-based EquationsTime-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. 500 MW Fossil 50 MW GT
235
Capacity-based EquationsCapacity-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.
500 MW Fossil
50 MW GT
236
Outside Management Control (OMC)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
What are OMC Events?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
What are OMC Events?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
More Information?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
Time-based IndicesTime-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
Time-based IndicesTime-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
Equivalent Availability Factor (EAF)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
What is meant by “Equivalent Derated What is meant by “Equivalent Derated Hours?”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
400
300
200
100
0
400
300
200
100
0
1 2 3 4
1 2 3 4
246
Equivalent Availability Factor (EAF)Equivalent Availability Factor (EAF)
EAF = (AH - ESDH - EFDH - ESEDH) x 100%PH
Where AH=7760; PH=8760; ESDH=50; EFDH= 500; ESEDH=10; MOH=440
EAF = (8760 – 50 - 500 -10 - 440) x 100% = 88.58%8760
247
Equivalent Unavailability Factor (EUF)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
Scheduled Outage Factor (SOF)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
Other Outage FactorsOther Outage Factors
Maintenance Outage Factor (MOF)
Planned Outage Factor (POF)
POF = 100% x (POH)PH
MOF = 100% x (MOH)PH
251
Forced Outage Factor (FOF)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
Net Capacity Factor (NCF)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
Net Capacity Factor (NCF)Net Capacity Factor (NCF)
NCF = 100% x (Net Actual Generation)[PH x (Net Maximum Capacity)]
255
Net Output Factor (NOF)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
Net Output Factor (NOF)Net Output Factor (NOF)
NOF = 100% x (Net Actual Generation)[SH x (Net Maximum Capacity)]
257
Comparing NCF and NOFComparing NCF and NOF
NCF = 100% x (Net Actual Generation)[PH x (Net Maximum Capacity)]
NOF = 100% x (Net Actual Generation)[SH x (Net Maximum Capacity)]
NCF measures % of time at full load.NOF measures the loading of the unit when operated.
258
Comparing AF/EAF/NCF/NOFComparing AF/EAF/NCF/NOF
NOF > NCF
AF > EAF > NCF
(Because SH is normally always be less than PH. What would be the exception?)
(What would cause these 3 numbers to be equal? What is its likelihood of occurring?)
259
What can you learn from the What can you learn from the numbers below?numbers below?
EAF NCF NOF
Nuclear 88.35 89.18 98.81
Fossil, coal 84.19 70.96 84.65
Fossil, gas 86.97 13.33 38.38
Fossil, oil 81.86 15.24 49.03
Gas turbines 90.20 2.67 66.70
Hydro 85.98 41.13 70.53
(Data for 2005-2009 GAR Report)260
Meeting Demand in Real TimeMeeting Demand in Real Time
Typical Daily Demand Curve
Base Load
Intermediate Load
Peak Load
Operating Reserves
Energy: Electricity Produced over Time
Capacity: Instantaneous measure of electricity available at peak
261
What can you learn from the What can you learn from the numbers below?numbers below?
(Data for 2005-2009 GAR Report)
EAF NCF NOF Age in '09
Nuclear 88.35 89.18 98.81 29.37
Fossil, coal 84.19 70.96 84.65 42.45
Fossil, gas 86.97 13.33 38.38 45.86
Fossil, oil 81.86 15.24 49.03 44.59
Gas turbines 90.20 2.67 66.70 26.96
Hydro 85.98 41.13 70.53 57.81
262
Forced Outage RateForced 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
Forced Outage RateForced Outage Rate
Calculation:
FOR = FOH FOH + SH + Syn Hrs + Pmp Hrs
Comparison: unit with high SH vs. low SH(SH = 6000 hrs vs. 600 hrs; FOH = 200 hrs)
FOR = 200 = 3.23% 200 + 6000
FOR = 200 = 25.00% 200 + 600
x 100%
265
Equivalent Forced Outage RateEquivalent 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
Equivalent Forced Outage RateEquivalent Forced Outage Rate
Calculation:
EFOR = FOH + EFDH . (FOH + SH + Syn Hrs + Pmp Hrs + EFDHRS)
where EFDH = (EFDHSH + EFDHRS)
EFDHSH is Equivalent Forced Derated Hours during Service Hours.
EFDHRS is Equivalent Forced Derated Hours during Reserve Shutdown Hours.
267
Equivalent Forced Outage RateEquivalent Forced Outage Rate
EFOR = FOH + EFDH . (FOH + SH + EFDHRS )
As an example:
FOH = 750, EFDH = 450, SH = 6482, EDFHRS=0, Syn Hrs = 0, Pmp Hrs = 0
EFOR = 750 + 450 . (750 + 6482 + 0 )
= 16.6%
268
Equivalent Forced Outage Rate – Equivalent Forced Outage Rate – Demand (EFORd)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
Equivalent Forced Outage Rate – Equivalent Forced Outage Rate – Demand (EFORd)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
Equivalent Forced Outage Rate – Equivalent Forced Outage Rate – Demand (EFORd)Demand (EFORd)
12
3
6
9
1
2
4
57
8
10
11
271
EFORd Equation:EFORd Equation:
EFORd= [(FOHd) + (EFDHd)] x 100% [SH + (FOHd)]
Where: FOHd = f x FOH f = [(1/r)+(1/T)]
[(1/r)+(1/T)+(1/D)]
r= FOH/(# of FOH occur.) T= RSH/(# of attempted Starts) D= SH/(# of actual starts) EFDHd = fp x EFDH
fp = SH/AH272
Example of EFORd vs. EFORExample of EFORd vs. EFOR
EFOR vs. EFORdGeneral Trend
0
20
40
60
80
100
120
140
Increasing RSH / Decreasing SH (All other numbers in calculation are contant.)
Per
cen
t E
FO
R &
EF
OR
d
EFOR
EFORd
EFOR, range from 6.2 to 130.0%
EFORd, range from 4.7 to 30.7%
273
Example of EFORd vs. EFORExample of EFORd vs. EFOR
EFOR vs. EFORdGas Turbines 2004-2008
0
10
20
30
40
50
60
70
80
90
100
Corresponding EFOR & EFORd Values
Per
cen
t E
FO
R &
E
FO
Rd
EFORd EFOR 274
Limiting Conditions for EFORdLimiting Conditions for EFORd
Case SH FOH RSH FORd EFORd
Base >0 >0 >0 Applicable Applicable
1 0 >0 >0Cannot be determined
Cannot be determined
2 0 0 >0Cannot be determined
Cannot be determined
3 0 >0 0Cannot be determined
Cannot be determined
4 >0 0 >0 0 EFDH/AH
5 >0 0 0 0 EFDH/SH
6 >0 >0 0 FOR EFOR
7 0 0 0Cannot be determined
Cannot be determined
Base case is normal. Cases 4, 5, 6: Computed FORd, EFORd are valid. 275
What can you learn from the What can you learn from the numbers below?numbers below?
(Data for 2005-2009 GAR Report)
FOR EFOR EFORd SH RSH
Nuclear 2.16 3.09 3.09 7,864.04 6.03
Fossil, coal 5.37 7.46 7.08 6,988.47 615.3
Fossil, gas 10.37 11.66 7.24 2,506.42 4,891.71
Fossil, oil 15.33 16.42 11.58 2,682.17 4,465.38
Gas turbines 53.73 54.10 8.86 241.14 7,823.34
Hydro 5.71 5.93 5.16 4,972.45 1,907.60
276
How to Avoid Misleading EFORdHow 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
EAF + EFOR = 100%?EAF + EFOR = 100%?
Given: PH = 8760, SH = 10, RSH = 8460. FOH = 290. No deratings
EAF = AF = AH PH
EAF = 8470 8760
EAF = 97.7%
EFOR = FOR = FOH__ (SH+ FOH)
EFOR = 290____ (290 + 10)
EFOR = 97.7%
Factors and rates Factors and rates are notare not additive additive and not complementary!and not complementary!
278
Other Equations in IEEE 762Other Equations in IEEE 762
Forced Outage Rate Demand- FORd
FORd = FOHd x 100% [FOHd + SH]
whereFOHd = f x FOH
r=Average Forced outage duration = (FOH) / (# of FO occurrences)D=Average demand time = (SH) / (# of unit actual starts)T=Average reserve shutdown time = (RSH) / (# of unit attempted starts)
f =
DTrTr111
/11
279
Other Equations in IEEE 762Other Equations in IEEE 762
Equivalent Maintenance Outage Factor
Equivalent Planned Outage Factor
Equivalent Forced Outage Factor
EMOF = 100% x (MOH + EMDH)PH
EPOF = 100% x (POH + EPDH)PH
EFOF = 100% x (FOH + EFDH)PH 280
Other Equations in IEEE 762Other Equations in IEEE 762
Equivalent Maintenance Outage Rate
Equivalent Planned Outage Rate
Equivalent Forced Outage Rate
EMOR = 100% x ( MOH + EMDH )(MOH+SH+Syn Hr+Pmp Hr+EMDHRS)
EPOR = 100% x ( POH + EPDH )(POH+SH+Syn Hr+Pmp Hr+EPDHRS)
EFOR = 100% x ( FOH + EFDH )(FOH+SH+Syn Hr+Pmp Hr+EFDHRS)
281
Comparing EAF, WEAF, XEAF, etc.Comparing EAF, WEAF, XEAF, etc.
EAF = (AH - ESDH - EFDH - ESEDH) x 100%PH
WEAF = Σ NMC(AH - ESDH - EFDH - ESEDH) x 100% Σ NMC (PH)
XEAF = (AH - ESDH - EFDH - ESEDH) x 100% PH
XWEAF = Σ NMC(AH - ESDH - EFDH - ESEDH) x 100% Σ NMC (PH)
283
Comparing EAF, WEAF, XEAF, etc.Comparing EAF, WEAF, XEAF, etc.
Fossil, All sizes, coal Nuclear Gas Turbines
EAF 84.64% 86.15% 90.28%
WEAF 84.25% 86.64% 90.06%
XEAF 85.21% 86.50% 90.76%
XWEAF 84.74% 86.98% 90.56%
284
Comparing EAF, WEAF, XEAF, etc.Comparing EAF, WEAF, XEAF, etc.
Combination of Fossil & Gas Turbine
EAF 81.82%
WEAF 83.68%
XEAF 82.68%
XWEAF 84.01%
285
Comparing EAF, WEAF, XEAFComparing 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
Commercial AvailabilityCommercial 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
Commercial AvailabilityCommercial Availability
Unit Available
Needed for Generation
Unit Available
Not needed for Generation
Unit not available
Not Needed for Generation
Unit not available
Needed for Generation
Make Big Revenue, +$
Lost opportunity, -$Good time for repairs
Not competitive, -$
289
Beware of Statistical ScatterBeware 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
Weighted Equivalent Availability Factor Weighted Equivalent Availability Factor
Fossil-Steam Units in USA for Year 2004-2008 Only
WEAF
10% 25% 50% Mean 75% 90%
100-199 MW 72.83 82.02 87.58 85.50 91.54 94.82
200-299 MW 76.30 81.91 86.16 84.82 89.44 91.96
300-399 MW 76.14 80.85 86.02 85.12 89.32 91.58
400-499 MW 73.45 80.84 85.92 84.37 89.01 92.71
500-599 MW 74.30 78.88 83.56 82.95 87.37 90.51
600-699 MW 75.39 80.91 85.77 84.87 89.15 91.60
700-799 MW 72.61 76.82 84.09 81.09 88.24 90.88
800-899 MW 82.13 84.65 87.76 87.78 91.70 92.57
292
Weighted Equivalent Availability Factor Weighted Equivalent Availability Factor
Fossil-steam units in USA; 2004-2008
Fossil Unit WEAF by Size
0
10
20
30
40
50
60
70
80
90
100
100-199MW
200-299MW
300-399MW
400-499MW
500-599MW
600-699MW
700-799MW
800-899MW
WE
AF
Per
cen
t
10%
25%
50%
Mean
75%
90%
293
WEAF and Age of Fossil UnitsWEAF and Age of Fossil UnitsAll Sizes and FuelsAll Sizes and Fuels
Fossil-steam units in USA 1982-2008
Fossil Unit Weighted Equiv. Availabliity Factor (WEAF) and Unit Age
0
10
20
30
40
50
60
70
80
90
1982
1984
1986
1988
1990
1992
1994
1996
1998
2000
2002
2004
2006
2008
% W
EA
F &
Un
it A
GE
in
Ye
ars
AGE
WEAF
294
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 DataWords About Pooling Data
296
Words About Pooling DataWords About Pooling Data
Example of the proper pooling for FOR for 5 units:
FOH = 840 + 78 + 67 + 117 + 546 = 1648 / 5 = 329.60
SH = 6760 + 7610 + 116 + 765 + 7760 = 23011 / 5 = 4602.20
Average FOR = [FOH/(FOH + SH)] X 100% = 100% x [329.60/(4602.20+ 329.60)] = 6.62%
*****************************************************
Example of the WRONG pooling of AF for 5 units:
Average FOR = (11.05% + 1.01% + 36.61% + 13.27% + 6.57%) = 68.51% / 5 = 13.70%
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GADS Standard for EFORdGADS 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).
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Pooling Time-based StatisticsPooling Time-based Statistics
Equivalent Maintenance Outage Factor
Equivalent Planned Outage Factor
Equivalent Forced Outage Factor
EMOF = 100% x Σ (MOH + EMDH)Σ PH
EPOF = 100% x Σ (POH + EPDH)Σ PH
EFOF = 100% x Σ (FOH + EFDH)Σ PH
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Pooling Weighted StatisticsPooling Weighted Statistics
Weighted Equivalent Maintenance Outage Factor
Weighted Equivalent Planned Outage Factor
Weighted Equivalent Forced Outage Factor
WEMOF = 100% x Σ [(MOH + EMDH) x NMC]Σ (PH x NMC)
WEPOF = 100% x Σ [(POH + EPDH) x NMC]Σ (PH x NMC)
WEFOF = 100% x Σ (FOH + EFDH) x NMC]Σ (PH x NMC)
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GADS and the World Energy CouncilGADS 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.
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Continuing ProjectsContinuing 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.
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Continuing ProjectsContinuing Projects
Adding wind generators to GADS
• Started database on concentrated solar and PV earlier this year. Still in the works…
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Exchange data with Europe and CEAExchange data with Europe and CEA
Exchange data with Europe and the Canadian Electricity Association (CEA)
Continue correspondence with the International Atomic Power Agency (IAEA)
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Design Data Time StampingDesign 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).
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Data Transmittal Tools
Media Specifications
E-mail:
Text format (.txt). To improve transmission times your data files may be submitted as compressed (.zip) files.
Submit your data within 30-days after the end of every calendar quarter.
E-mail your data to: [email protected]
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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.
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Access to pc-GARAccess 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.
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