NERC GADS 101 Data Reporting Workshop

NERC GADS 101 Data Reporting Workshop
G. Michael Curley Manager of GADS Services October 27-29, 2010

Welcome GADS Services Staff Please stand and introduce yourselves
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

Overview of Attendees at this Conference
Representatives of: Generating companies (IOU, IPPs, Government, etc) Consultants Insurance ISOs

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

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

Agenda Introduction and welcoming remarks
What is NERC? What is GADS? Fundamentals on the three GADS Databases Event What are the elements of the event database? Performance What are the elements of the performance database? Design What makes up the design database?

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

NERC is the ERO

NERC Background NERC started in 1968.
NERC chosen as the ERO for the US in 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.

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.

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.

About NERC International regulatory authority for electric reliability in North America Develop & enforce reliability standards Analyze system outages and near-misses & recommend improved practices Assess current and future reliability 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.

Meeting Demand in Real Time
Typical Daily Demand Curve Operating Reserves Peak Load Capacity: Instantaneous measure of electricity available at peak Intermediate Load Base Load Energy: Electricity Produced over Time

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 8 Regional Reliability Organizations 4 synchronous Interconnections

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

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

Work now… Marry the transmission to the generation databases, using Section 1600 of the Rules of Procedure.

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.

Rules of Procedure: Section 1600 Overview
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.”

Rules of Procedure: Section 1600 Request 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

Rules of Procedure: Section 1600 Procedure
Acting Subgroup NERC Approval Committees Not Approved Submit Data Request to DCS Submit Data Request to PC Draft Data Request Not Approved Data Rule In Effect FERC Comment Period Public Comment Period Submit Data Request File Data Request (21 Days) Post Data Request (45 Days) No Appeal Collect, Respond, & Post Comments NERC Board of Trustees Affected Parties Submit Final Data Request Appeal (30 Days) Finalize Data Request Approved Not Approved

Rules of Procedure: Section 1600 Limitations
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

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.

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.

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.

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 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.

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.

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).

More information? Please visit our website: www.nerc.com
Most information is open to the public.

Question & Answer

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

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

Example – Benchmarking – Distributions
[Fossil-steam units MW; Coal fuel; 6,500+ Service Hours/Yr.; ; (79 units from 73 companies)]

Example – Benchmarking – Top Problems
[Fossil-steam units MW; Coal fuel; 6,500+ Service Hours/Yr.; ; (79 units from 73 companies)]

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!

GADS Monitor the Present
Generator “C” Generator “B” Generator “D” GADS Generator “A” Generator “E” 5,800+ generating units including 2 international affiliates.

International 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.

GADS 2009 Data Reporting 5,874 units reported in 2009, 0.9% increase in the number of units reporting over 2008!

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.

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.

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

Question & Answer

The GADS Data Monster

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.

Design Data Reporting (Section V)

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.

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

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

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.

Example of Design Data Form

Performance Reporting (Section IV)

Why collect performance records?
Collect generation of unit on a monthly basis. Provide a secondary source of checking event data. Allows analysis of fuels

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.

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

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)

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.

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!

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

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!

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

Effect of Ambient Temperature

Maximum and Dependable Capacity
What is the difference between Maximum and Dependable? GMC - GDC = Ambient Losses NMC - NDC = Ambient Losses

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)

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: Miscellaneous: 4.0% difference between gross and net values

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)

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!

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

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.

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)

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

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.

Unit Time Information Service Hours (SH) Reserve Shutdown Hours (RSH)
Number of hours synchronized to system Reserve Shutdown Hours (RSH) Available for load but not used (economic)

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

Question & Answer

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).

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.

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.

Calendar Hours Sum of Period Hours + Inactive Hours For most cases, Period Hours = Calendar Hours

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?

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.

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%}

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.

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

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)

Fuel Codes Fuel Codes 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.)

Question & Answer

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?

There is no such thing as a nuclear powered gas turbine!

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?

Quick Quiz (cont.) Answer: There is no derating!
NMC – NDC = 100 – 100 = 0 (zero)

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?

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)

Event Reporting (Section III)

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.

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.

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)

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

One Event for One Outage
Month 1 Month 2 Month 3 Event 1

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?

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

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

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.

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

Unit States

Unit States – Inactive

Unit States – Inactive (cont.)
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

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.

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.

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.

Unit States – Active

Event Type (required 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

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!

From the Unit States Diagram
“Unplanned” Forced + Maintenance + Planned

From the Unit States Diagram
Forced + Maintenance + Planned “Scheduled”

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.

Scheduled-type Outages Planned Extension (PE) – continuation of a planned outage. Maintenance Extension (ME) – continuation of a maintenance outage.

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.

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

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

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.

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

Example #1 – Simple Outage
Jan 0430 Jan 1700 Forced Outage CC 4240 Capacity (MW)

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?

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?

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!

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?

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?

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.

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?

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?

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.

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?

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).

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?

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?

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.

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?

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?

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.

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?

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?

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.

More Examples? Appendix G – Examples and Recommended Methods
Reporting Outages to the Generating Availability Data System (GADS)

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.)

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

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.

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.

Any questions about outages?

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.

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.

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

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.

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).

Scheduled Deratings (cont.) Planned Extension (DP) – continuation of a planned derate. Maintenance Extension (DM) – continuation of a maintenance derate.

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.

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

Example #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.

Example #2 – Simple Derating
Jan 0800 Jan Derating

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

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.

Event Description: Riverglenn #1 had an immediate 100 MW derating on
Example #3 - Overlapping Deratings Second Starts & Ends Before First (G-3A) Event Description: Riverglenn #1 had an immediate 100 MW derating on March 9 at 8:45 a.m. due to a failure of the ‘A’ pulverizer feeder motor. Net Available Capacity (NAC) is 500 MW. At 10:00 a.m. the same day, another 100 MW (NAC = 500 MW) loss occurs with the failure of ‘B’ pulverizer mill. Failure of the ‘B’ mill is repaired after 1 hour when a foreign object is removed from the mill. The ‘A’ motor is repaired and returned to service on March 9 at 6:00 p.m.

Example #3 - Overlapping Deratings Second Starts & Ends Before First (G-3A)
Capacity (MW) Forced Derating CC 0250 D1 CC0320

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.

Example #4 - Overlapping Derating (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.

Example #4 - Overlapping Derating (1st is Shadowed by the 2nd) with Dominant Code
Capacity (MW) D4 CC 3112 D1 CC 3410

Dominant Derating Code
300 400 500 600 700 Capacity (MW) D4 CC 3112 D1 CC3410 Event #1 Event #2 Event #3 Without Dominant Derating Code With Dominant Derating Code 3 events to cover 2 incidents 2 events to cover 2 incidents

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.

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.

Normal Deratings Event 1 Event 2

Single Dominant Derating Dominant Derating – Event 3

Overlapping Dominant Deratings Dominant Derating – Event 4 Dominant Derating – Event 3 Dominant Derating 3 SHADOWS portion of Event 4

Overlapping Dominant Deratings by Virtue of Loss Dominant Derating – Event 3 Derating – Event 4 takes the dominant position. Derating – Event 4

Advantages are: Shows true impact of equipment outages for big, impact problems Reduces reporting on equipment Shows true frequency of outages.

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.

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.

Any questions about deratings?

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?

Question & Answer

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!

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

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 …

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!

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!

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

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

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.

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

Question & Answer

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

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?

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

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?

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

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?

No! All ramp up and safety checks are all with the normal time for the unit.

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?

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.

Question & Answer

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

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

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 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.

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

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.

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.

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

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”

Event 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

Event Contribution Codes (cont.)
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.

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.

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

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

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

Compare the difference ...
Method 1 Method 2 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.”

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

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)

Question & Answer

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?

Quick Quiz (cont.) Answer: 1800 - Major Boiler overhaul
more than 720 hours Minor Boiler overhaul 720 hours or less

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?

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

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

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.

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?

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

Riverglenn #1 experienced a FO as follows: Start date/time: October 1545 End date/time: October 1321 GAC: NAC: Cause Code: 1455 Description: ID fan vibration, fly ash buildup on blades Is this event reported correctly?

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.

Review of Standard Terms and Definitions Used by the Electric Industry

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.

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!

Unit States

From the Unit State Chart …
“Unplanned” – corrective action Forced + Maintenance + Planned

From the Unit State Chart …
Forced + Maintenance + Planned “Scheduled” - preventive

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.

Two Classes of Equations
Time-based All events Without Outside Management Control (OMC) Capacity- or Energy-based

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. 500 MW Fossil 50 MW GT

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. 500 MW Fossil 50 MW GT

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.

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

What are OMC Events? Lack of fuels Labor strikes
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

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.

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)

Time-based Indices Energy Factors Rates Net Capacity Factor (NCF)
Net Output Factor (NOF) Rates Forced Outage Rate (FOR) Equivalent Forced Outage Rate (EFOR) Equivalent Forced Outage Rate – Demand (EFORd)

Time-based Equations – Factors

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.

What is meant by “Equivalent Derated Hours?”
400 300 200 100 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

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 – ) x 100% = 88.58% 8760

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.

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.

Scheduled Outage Factor (SOF)
SOF = 100% x (POH + MOH) PH

Other Outage Factors Maintenance Outage Factor (MOF)
Planned Outage Factor (POF) MOF = 100% x (MOH) PH POF = 100% x (POH) PH

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.

Forced Outage Factor (FOF)
FOF = 100% x (FOH) PH

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”).

Net Capacity Factor (NCF)
NCF = 100% x (Net Actual Generation) [PH x (Net Maximum Capacity)]

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.

Net Output Factor (NOF)
NOF = 100% x (Net Actual Generation) [SH x (Net Maximum Capacity)]

NCF = 100% x (Net Actual Generation) [PH x (Net Maximum Capacity)]
Comparing 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.

Comparing 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?)

What can you learn from the 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 GAR Report)

Meeting Demand in Real Time
Typical Daily Demand Curve Operating Reserves Peak Load Capacity: Instantaneous measure of electricity available at peak Intermediate Load Base Load Energy: Electricity Produced over Time

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 (Data for GAR Report)

Time-based Equations – Rates

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.

FOH + SH + Syn Hrs + Pmp Hrs x 100%
Forced Outage Rate Calculation: FOR = FOH FOH + SH + Syn Hrs + Pmp Hrs x 100% Comparison: unit with high SH vs. low SH (SH = 6000 hrs vs. 600 hrs; FOH = 200 hrs) FOR = = 3.23% FOR = = 25.00%

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.

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.

As an example: FOH = 750, EFDH = 450, SH = 6482, EDFHRS=0, Syn Hrs = 0, Pmp Hrs = 0 EFOR = FOH + EFDH (FOH + SH + EFDHRS ) EFOR = ( ) = 16.6%

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.

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.

12 3 6 9 1 2 4 5 7 8 10 11

EFORd= [(FOHd) + (EFDHd)] x 100% [SH + (FOHd)]
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/AH

Example of EFORd vs. EFOR
EFOR, range from 6.2 to 130.0% EFORd, range from 4.7 to 30.7%

Example of EFORd vs. EFOR

Limiting Conditions for EFORd
Case SH FOH RSH FORd EFORd Base >0 Applicable 1 Cannot be determined 2 3 4 EFDH/AH 5 EFDH/SH 6 FOR EFOR 7 Base case is normal. Cases 4, 5, 6: Computed FORd, EFORd are valid.

FOR EFOR EFORd SH RSH Nuclear 2.16 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 (Data for GAR Report)

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.

EAF + EFOR = 100%? Factors and rates are not additive
Given: PH = 8760, SH = 10, RSH = FOH = 290. No deratings EAF = AF = AH PH EAF = 8470 8760 EAF = 97.7% EFOR = FOR = FOH__ (SH+ FOH) EFOR = ____ ( ) EFOR = 97.7% Factors and rates are not additive and not complementary!

Other Equations in IEEE 762
Forced Outage Rate Demand- FORd FORd = FOHd x 100% [FOHd + SH] where FOHd = f x FOH f = 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)

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

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)

Question & Answer

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)

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%

Combination of Fossil & Gas Turbine EAF 81.82% WEAF 83.68% XEAF 82.68% XWEAF 84.01%

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.

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.

Unit Available Not needed for Generation Unit Available Needed for Generation Not competitive, -$ Make Big Revenue, +$ Unit not available Not Needed for Generation Unit not available Needed for Generation Good time for repairs Lost opportunity, -$

Words About Distributions

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.

Weighted Equivalent Availability Factor
Fossil-Steam Units in USA for Year Only WEAF 10% 25% 50% Mean 75% 90% MW 72.83 82.02 87.58 85.50 91.54 94.82 MW 76.30 81.91 86.16 84.82 89.44 91.96 MW 76.14 80.85 86.02 85.12 89.32 91.58 MW 73.45 80.84 85.92 84.37 89.01 92.71 MW 74.30 78.88 83.56 82.95 87.37 90.51 MW 75.39 80.91 85.77 84.87 89.15 91.60 MW 72.61 76.82 84.09 81.09 88.24 90.88 MW 82.13 84.65 87.76 87.78 91.70 92.57

Weighted Equivalent Availability Factor
Fossil-steam units in USA;

WEAF and Age of Fossil Units All Sizes and Fuels
Fossil-steam units in USA

Words About Pooling Data

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.

Example of the proper pooling for FOR for 5 units: FOH = = / 5 = SH = = / 5 = Average FOR = [FOH/(FOH + SH)] X 100% = 100% x [329.60/( )] = 6.62% ***************************************************** Example of the WRONG pooling of AF for 5 units: Average FOR = (11.05% % % % %) = 68.51% / 5 = 13.70%

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).

Pooling 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

Pooling 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)

What’s new with GADS?

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.

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.

Continuing Projects Adding wind generators to GADS
Started database on concentrated solar and PV earlier this year. Still in the works…

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)

Design Data Time Stamping

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).

Closing Comments

Data Transmittal Tools
Media Specifications 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. your data to:

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.

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.

Question & Answer Contact: Mike Curley Manager of GADS Services

NERC GADS 101 Data Reporting Workshop

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