gads 101 data reporting workshop

GADS 101 Data Reporting WorkshopTRE Workshop – Austin, TXNovember 3, 2011

2 RELIABILITY | ACCOUNTABILITY

Welcome

• GADS Services Staff Mike Curley – Manager of GADS Services

• Please stand and introduce yourselves Your name, company and experience with GADS


What’s on the Flash Drive?

Slides for GADS training 2012 GADS Data Reporting Instructions GADS Data Entry and Edit Program GADS Services Pricing Schedule Demo of pc-GAR & pc-GAR MT software pc-GAR Order Forms GADS Wind Turbine Generation Data Reporting

Instructions GADS Wind Generation Data Entry Software GADS Design software World Energy Council (WEC) reports


Agenda

• Introduction and welcoming remarks What is NERC? What is GADS?

oWhy mandatory GADS?oWhat units are required?oWhat is Section 1600 of the Rules of Procedure?

• What’s new with GADS? Move to webE-GADS in 2012.


Agenda

• 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?


Agenda (cont.)

• Data release policies• Data applications• IEEE 762 Equations and their meanings (Metrics)

What are the equations calculated by GADS? What are they trying to tell you? Review of standard terms and equations used by the

electric industry.


What is NERC?

• November 9,1965 Northeast black out 30 million people affected $100 million of economic losses

• 1967 Federal Power Commission investigation. Recommends “council on power coordination.”

• 1968 Regional groups formed NERC


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


NERC is the ERO

10 RELIABILITY | ACCOUNTABILITYRELIABILITY | ACCOUNTABILITY

Meeting 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


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 bulkpower system mandatory and enforceable.

• Electric Reliability Organization (ERO) Self-regulating reliability organization 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

• 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


• NERC is not a utility, association, institute, or a government organization.

• NERC is a not-for-profit, international (US, Canada, and Mexico) corporation.

What is NERC?


Question & Answer


What is GADS?

A - Availability

S - System

G - Generating

D - Data


Generating Unit Database

North American UtilityDatabase

Standard Terminology

IEEE

1960’s - 1970’s

EEI

EPRI

FPC


GADS is Born!

EEI

NERC1979


What is GADS?

• Generating unit availability database • Critique the past• Monitor the present• Assess the future


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!


Critique the Past

• Conduct special studies High impact/low probability studies

• Produce annual GADS publications Generating Availability Report publication GADS Brochure

• Perform benchmarking services… and more


Monitor the Present

GADS

Generator “B”

Generator “A”

Generator “C”

Generator “D”

Generator “E”

5,900+ generating units including international affiliates.


GADS 2010 Data Reporting

5,963 units reported in 2010!


Mandatory GADS in 2012


Need for GADS Data

TADS and DADS are already mandatory. GADS is the final step.


GADS Task Force

• Mandatory GADS submission discussed for many years.

• In June 2010, the PC impaneled a task force to evaluate the status of GADS need for mandatory submission: About 73% of the installed capacity (20 MW or larger)

reports outage events to GADS. Currently voluntary database In 2011, the NERC RIS, PC and Board of Trustees

recommended mandatory submission for conventional units (fossil, nuclear, combined cycle, etc).


What are “Conventional Generating Units?”

• The ten types of conventional generating units: Fossil steam including fluidized bed design; Nuclear; Gas turbines/jet engines (simple cycle and others modes); Internal combustion engines (diesel engines); Hydro units/pumped storage; Combined cycle blocks and their related components (gas turbines and steam

turbines); Cogeneration blocks and their related components (gas turbines and steam turbines); Multi-boiler/multi-turbine units; Geothermal units; and Other miscellaneous conventional generating units (such as variable fuel – biomass,

landfill gases, etc) used to generate electric power for the grid and similar in design and operation as the units shown above and as defined by the GADS Data Reporting Instructions.


What are “Conventional Generating Units?

• No Renewable!!!!!! No Wind No Solar (At this time …)


The Need For GADS Data

• Historically: Reliability Assessment reports and modeling Loss-of-load Expectation studies and modeling

• New Challenges As the resource mix changes, NERC and its stakeholders

will need to understand how the changes in resource performance translates into Planning Reserve Margins.

Understand the performance of existing and new resource technologies is essential to comprehending the reliability of the projected bulk power system in North America.


The Need For GADS Data (cont’d)

• Performance Analysis Historical event data used to develop a severity metric risk

measurement tool, establishing the bulk power system’s characteristic performance curve.

To calculate and measure both Event and Condition Driven risk, detailed event, and performance information

Monitoring the impact of transmission outages on generators and generator outages on transmission.

Power plant benchmarking, equipment analysis, design characteristics, projected performance, avoid long-term equipment/unit failures, etc.


Justifications For Conventional Units

• Nearly 300 GW are not reported GADS.• Nearly 50% of new units 2000-2008 do not report • Large amounts of hydro-pumped storage, combined

cycle and gas turbines are missing. • These units are needed to analyze the reliability of the

bulk power system.


Recommendations – Process and Security

• The task force recommends that GADS data be provided from all NERC Compliance Registry Generator Owners, following Section 1600, Requests for Data or Information under NERC’s Rules of Procedures.

• GADS data confidentiality will be covered under NERC’s Rules of Procedure Section 1500, Confidential Information.


Recommendations - Unit Types

• The ten types of conventional generating units will be required under the mandatory rule: Fossil steam including fluidized bed design; Nuclear; Gas

turbines/jet engines (simple cycle and others modes); Internal combustion engines (diesel engines); Hydro units/pumped storage; Combined cycle blocks and their related components (gas turbines and steam turbines); Cogeneration blocks and their related components (gas turbines and steam turbines); Multi-boiler/multi-turbine units; Geothermal units; and Other miscellaneous conventional generating units used to generate electric power for the grid as defined by the GADS Data Reporting Instructions.


Recommendations – MW Sizes and When

• Generator Owners shall report their GADS data to NERC as outlined in the GADS Data Reporting Instructions (Appendix III) for design, event and performance data for generating unit types listed above for units 50 MW and larger starting January 1, 2012 and 20 MW and larger starting January 1, 2013

• Generator Owners not listed on NERC’s Compliance Registry may report to GADS on a voluntary basis.

• All small MW units invited but are voluntary.


Multi-units on Meters

10 MW 10 MW 10 MW 10 MW

10 MW 10 MW 10 MW 10 MW 10 MW

10 MW

Meter

Meter

Meter Meter Meter Meter

Not Required Reporting to GADS – Treat as Normal Unit.

Reportable to GADS – Treat as “Miscellaneous Unit”


What is Meant by “MW Nameplate?”

• “MW Nameplate” is calculated by multiplying the MVA recorded of the generator times the power factor. For example, a 100 MVA unit with a .90 power factor

would be a 90 MW unit. Generator Owners not listed on NERC’s Compliance Registry may report to GADS on a voluntary basis.


Recommendations – Modify Reporting

Software

• There will be a one-time effort by non-reporting generating companies to modify their existing computer data collection program outputs into GADS required formats. The GADSTF believes that equipment outage data is already collected by plant personnel, although they may not adhere to GADS requirements.


Recommendations - Uniformity

• Uniformity of data collection format is essential. All GADS data shall be collected using the GADS Data Reporting Instructions. The Reporting Instructions will be updated annually and each reporting company will be required to follow the latest Reporting Instructions for the current year. All questions or needs for interpretation of the reporting instruction interpretations will be coordinated with NERC staff and the GADSTF. Updates will follow the Section 1600 process.


Recommendations – In-house Audits

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


Recommendations - Design

• Design data is essential for many generating plant analyses. Generating companies will be asked to review and update their design data annually or as recommended by NERC staff using the design time-stamping process, but the updating will be voluntary.

• The GADSTF leadership recommended that the design data requirement be nine (9) elements per unit, regardless of unit type.



• The nine design data fields were chosen for two specific reasons: Allowing GADS data to be matched with information

collected in the Transmission Availability Data System (TADS). One goal of NERC is to allow the GADS and TADS databases to interact with each other. Certain data fields are needed to allow generating units to be located in areas where transmission lines are located. Specific fields allow that interaction.

Editing the event and performance data to insure the continued quality of information collected by GADS.



• GADS utility code (assigned by GADS Services)• GADS unit code (assigned by the reporting company following the

guidelines in Appendix C of the GADS Data Reporting Instructions.)• NERC Regional entity where the unit is located• Name of the unit• Commercial operating date• Type of generating unit (fossil, combined cycle, etc.)• MW size (nameplate)• State or province location of the unit.• Energy Information Administration (EIA) Plant number (US units

only).


Recommendations – Ownership/Retirement

• NERC shall track ownership changes as generating units are sold to other operating companies. These changes will include the name of the new owners and the date of generating unit transfer.(Please note that GADS has been collecting ownership transfers for 10 years with no burden on reporters.)

• Proposed or projected generating units retirement dates shall not be collected in GADS


Question & Answer


What’s new with GADS?


Move to WebE-GADS


Move to webE-GADS

In August 2011, NERC signed a contract with OATI to collect GADS data starting in 2012.


Move to webE-GADS

• In preparation, GADS is moving away from old event and performance record formats (97/95) and accepting only the latest formats (07/05) starting this year.

• All data sent to GADS should be year-to-date January – September, not September only.

• New formats allow cause code amplification codes (required as of January 1, 2011) for U1 events only.


Move to webE-GADS

• Beta testing of webE-GADS will begin during the first quarter of 2012. Beta testers are needed.

• Training on using webE-GADS will also be during the first quarter of 2012.

• Once webE-GADS is up and operating, then no more data will be sent to [email protected] or Mike Curley.


Question & Answer


GADS and the WEC

• 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

• Addition of wind generators and solar to GADS Working group formed to determine design,

event, cause codes, etc. for data collection. Voluntary data collection at this point.


Continuing Projects

• Finishing coordination of definitions and other differences with Canadians (Canadian Electricity Association – CEA).

• Continue correspondence with International Atomic Energy Association (IAEA) and Institute of Nuclear Power Operations (INPO).


More information?

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


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)

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


Required Design Data

• GADS utility code (assigned by GADS Services)• GADS unit code (assigned by the reporting company following the

guidelines in Appendix C of the GADS Data Reporting Instructions.)• NERC Regional entity where the unit is located• Name of the unit• Commercial operating date• Type of generating unit (fossil, combined cycle, etc.)• MW size (nameplate)• State or province location of the unit.• Energy Information Administration (EIA) Plant number (US units

only).


Nine Required Design Data Fields


Multi-units on Meters

10 MW 10 MW 10 MW 10 MW

10 MW 10 MW 10 MW 10 MW 10 MW

10 MW

Meter

Meter

Meter Meter Meter Meter

Not Required Reporting to GADS – Treat as Normal Unit.

Reportable to GADS – Treat as “Miscellaneous Unit”


Combined Cycles

Fuel In Power OutCombined Cycle Block

ST

GT #2

GT #1 Power Out

Fuel In

Fuel In


Design Data Forms are Voluntary!

• Forms are located in Appendix E are all voluntary reporting!

• Complete forms when: Utility begins participating in GADS Unit starts commercial operation Unit’s design parameters change such as a new

FGD system, replace the boiler, etc.


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, 2012, GADS only accepts the new format.

o Only format accepted by webGADS


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 By the end of April, July, October, January


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 (voluntary) Original Reports (0) Additions or corrections (1, 2,…9) Report all records to a performance report if you revise just

one of the records.


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 (voluntary) 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 (required) 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 betweenMaximum 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: 2.0% difference between gross and net values

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.


Unit Loading (voluntary)

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 (required) Attempts to synchronize the unit Repeated failures for the same cause without attempted

corrective actions are considered a single start Repeated initiations of the starting sequence without

accomplishing corrective repairs are counted as a single attempt.

For each repair, report 1 attempted starts.• Actual Unit Starts (required)

Unit actually synchronized to the grid


Attempted & Actual Unit Starts

• If you report actual start, you must report attempted.

• If you do not keep track then: Leave Starts Blank GADS editor will estimate both attempted and actual starts

based on event data.• The GADS program also accepts “0” in the attempts

field if actual = 0 also.


Unit Time Information

• Service Hours (SH) (required) Number of hours synchronized to system

• Reserve Shutdown Hours (RSH) (required) Available for load but not used (economic)


Unit Time Information (cont.)

• Pumping Hours (required) Hours the hydro turbine/generator operated as a

pump/motor• Synchronous Condensing Hours (required)

Unit operated in synchronous mode Hydro, pumped storage, gas turbine, and jet engines

• Available Hours (AH) (required) Sum of SH+RSH+Pumping Hours+ synchronous condensing

hours


Question & Answer



• Planned Outage Hours (POH) (required) Outage planned “Well in Advance” such as the annual unit

overhaul. Predetermined duration. Can slide PO if approved by ISO, Power Pool or dispatch

• Forced Outage Hours (FOH) (required) Requires the unit to be removed from service before the

end of the next weekend (before Sunday 2400 hours)• Maintenance Outage Hours (MOH) (required)

Outage deferred beyond the end of the next weekend (after Sunday 2400 hours).



• Extensions of Scheduled Outages (ME, PE) (required) Includes extensions from MOH & POH beyond its estimate

completion date or predetermined duration. Extension is part of original scope of work and problems

encountered during the PO or MO. If problems not part of 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) (required) Sum of POH+FOH+MOH+PE+ME

• Period Hours or Active (PH) (required) Sum of Available + Unavailable Hours

• Inactive Hours (IH) (required) The number of hours the unit is in the inactive state

(Inactive Reserve, Mothballed, or Retired.) Discussed later in detail.



• 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?


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.


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. • Check the NMC of the unit. You can adjust NMC

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 (voluntary)• Average Heat Content (voluntary)• % Ash (voluntary)• %Moisture (voluntary)• % Sulfur (voluntary)• % Alkalis (voluntary)• Grindability Index (coal only)/

% Vanadium and Phosphorous (oil only) - (voluntary)• Ash Softening Temperature (voluntary)


Fuel Codes

Code Description Code Description

CC Coal PR Propane

LI Lignite SL Sludge Gas

PE Peat GE Geothermal

WD Wood NU Nuclear

OO Oil WM Wind

DI Distillate oil SO Solar

KE Kerosene WH Waste Heat

JP JP4 or JP5 OS Other – Solid (Tons)

WA Water OL Other – Liquid (BBL)

GG Gas OG Other – Gas (Cu. Ft.)

Fuel Codes


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?


Quick Quiz (cont.)

Answer: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)


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?


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 Event 1 Event 1

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 oHours of outageoCause 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 (voluntary) Original Reports (0) Additions or corrections (1, 2,…9) Report all records to a performance report if you revise just

one of the records.• Event Type – describes the event experienced by the

unit (required) Inactive Active


Unit States


Unit States – Inactive


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



• 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 -- 17 choices) Two-character code describes the event (outage, derating, reserve

shutdown, or non-curtailing).

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


“Scheduled”



• Scheduled-type Outages Planned Outage (PO)

o Outage planned “Well in Advance” such as the annual unit overhaul.

o Predetermined duration.o Can slide PO if approved by ISO, Power Pool or dispatch

Maintenance (MO) - deferred beyond the end of the next weekend but before the next planned event (Sunday 2400 hours)o If an outage occurs before Friday at 2400 hours, the above

definition applies. o But if the outage occurs after Friday at 2400 hours and

before Sunday at 2400 hours, the MO will only apply if the outage can be delayed passed the next, not current, weekend.

o If the outage can not be deferred, the outage shall be a forced event.



• 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 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: 01010000 End of Event: 01010001



• 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) – does not required immediate removal from service, but requires removal within six (6) hours. This type of outage can only occur start if the unit is in service.

Postponed (U3) – does not required immediate removal from service but is postponed beyond six (6) hours, and requires removal from service before the end of the next weekend. This type of outage can only start if the unit is in service.



• 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.


Is That Really a U1 Outage?

• Of the 32,987 FO events in 2010, 88.1% are U1 outages

(29,061events) 7.4 % are SF outages

(2,447 events) 2.8 % are U2 outages

(917 events) 1.7 % is U3 outages (559

events)

• With U1, you need an cause code amp code!

• If a boiler leak is detected and the unit remains in service for 2-4 more hours before starting to shut down for repairs, then the boiler tube leak is a U2 event, not a U1.


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 3 @ 0430 Jan 8 @ 1700

Forced Outage CC 4240

Capacity (MW)


Scenario #1: FO or MO?

• There was a boiler tube leak 4 days before the scheduled PO. The average repair time for such a leak is 36 hours.

• The unit cannot stay on line until the next Monday and must come down within 6 hours.

• Dispatch cleared the unit to come off early for repairs and PO.

• What type of outage is this?






• What type of outage is this? • Answer: First 36 hours is a U2 outage to fix tube leak

then change to PO. Why?






• 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!



• On Thursday at 10 a.m., the operators discovered vibration on the unit’s ID Fan.

• The unit could stay on-line until the next Monday, but dispatch allows the unit to come off-line Friday morning. On Friday, the dispatch reviewed the request again and allowed unit to come off for repairs.






• What type of outage is this?• Answer: MO. Why?





• What type of outage is this?• Answer: The unit could have stayed on line until the

end of the next weekend if required.



• A gas turbine started vibrating and vibration increased until after peak period. The GT had to come off before the end of the weekend.

• Dispatch said that the GT would not be needed until the next Monday afternoon.






• What type of outage is this? • Answer: FO. Why?





• 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. Your combined cycle has a HRSG tubeleak and must come off line now. (It’s 2x1 but there is no by-pass capabilities. )

• Dispatch said CC will not be needed for remainder of week.

• Your management decided to repair the unit on regular maintenance time to save costs. Over the next 36 hours, the HRSG was repaired. (The normal HRSG repairs take 12 hours of maintenance time.)

• What type of outage is this and for how long?


Scenario #4: FO or RS?

• It’s Monday. Your combined cycle has a HRSG tubeleak and must come off line now. (It’s 2x1 but there is no by-pass capabilities. )

• Dispatch said CC will not be needed for remainder of week.

• Your management decided to repair the unit on regular maintenance time to save costs. Over the next 36 hours, the HRSG was repaired. (The normal HRSG repairs take 12 hours of maintenance time.)

• What type of outage is this and for how long? • Answer: FO as long as the unit is not operable – full 36

hours then RS. Risk Management (CA).


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.


Commercial 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, -$


Scenario #5: PE or FO?

• During the 4 week PO, the repairs on the Electrostatic Precipitator (ESP) were more extensive then planned.

• At the end of the 4 week, the ESP work is not completed as outlined in the original scope of work. 3 more days is required to complete the work.

• What type of outage is the extra 3 days?





• What type of outage is the extra 3 days?• Answer: PE. Why?





• 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 the 4 week MO, the mechanics discovered Startup BFP seals needed replacing. (not part of scope.)

• At the end of the 4 week, the SBPF work was not completed because no parts on site. There was 12 hour delay in startup to complete work on SBFP.

• What type of outage is the extra 12 hours?





• What type of outage is the extra 12 hours?• Answer: FO. Why?





• 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?






• Answer: remains PO for full time. Why?






• Answer: work completed with scheduled PO time.


More Examples?

Appendix G – Examples and Recommended Methods

Reporting Outages to the Generating AvailabilityData 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.


Outages Cannot Overlap

Outage #1 Outage #2 Outage #1Outage #2X

Two outages can’t occurat the same time!

Acceptable Transition Not Acceptable Transition

Two outages end/startat the same time!


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. 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!

o Report a 1-hour derate with 1% reductiono 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.


Is That Really a D1 Derate?

• In 2010, there were 81,537 forced derating events 92.6% are D1 derates

(75,521 events) 5.1% are D2 derates

(4,160 events) 2.3% are D3 derates

(1,853 events)

• Not all forced derates are D1 events!

• No derates require amp codes.

• If the operator detects vibration on a fan and removes it from service 4 hours later, it is a D2, not D1 event.



• 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.



Maximum CapacitySeasonal 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


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.


Simple Derating

Jan 10 @ 0800 Jan 11 @1600

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.


Overlapping Deratings - 2nd Starts & Ends Before 1st Ends

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.


Overlapping Deratings - 2nd Starts & Ends Before 1st Ends

3/9@:0845 3/9@1800

Capacity (MW)

Forced Derating CC 0250

D1 CC0320

3/9@1000 3/9@1100


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.


Overlapping Derating - 2nd is Shadowed by the 1st

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.


Overlapping Derating - 2nd is Shadowed by the 1st

7/3@1430 7/23@1145

Capacity (MW)D4 CC 3112

D1 CC 3410

7/19@1115 7/19@1200


Dominant 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 incidents


Dominant Derating Code (cont.)

• How do you know if a derating is dominant? If you’re not sure, ask!

oPlant control room operatoroPlant 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 DeratingsNormal Deratings

Event 1

Event 2



Single Dominant DeratingSingle Dominant Derating

DominantDerating –Event 3



Overlapping Dominant DeratingsOverlapping Dominant Deratings



Dominant Derating 3 SHADOWS portion of Event 4



Overlapping Dominant Deratings by Virtue of LossOverlapping Dominant Deratings by Virtue of Loss

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.

• Non-curtailing – equipment or major component removed from service for maintenance/testing and does not result in a unit outage or derating.

• Rata testing?• Generator Doble testing?


Question & Answer


Event Magnitude

• Impact of the event on the unit (required)• 4 elements per record:

Start of event End of event Gross derating level Net derating level

• If you do not report gross or net levels, it will be calculated!



Maximum CapacitySeasonal Derating = Maximum Capacity - Dependable Capacity

Dependable Capacity Basic Planned Derating

PlannedDerating 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



• 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.)

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


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?


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?


Quick Quiz (cont.)

Answer:Change the U2 to an SF


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?


Quick Quiz (cont.)

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


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?


Quick Quiz (cont.)

Answer:No! All ramp up and safety checks are all within the normal time for that unit.


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?


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.


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 (required) 4-digit number (See Appendix B) 1,600+ cause codes currently in GADS Points to equipment problem or cause, not a detailed

reason for the outage/derate! Set of cause codes for each type of unit.

oCause codes for fossil-steam units onlyoCause codes for hydro units only


Cause Codes for Each Unit Type

• Fossil • Fluidized Bed Fossil• Nuclear• Diesel• Hydro/Pumped Storage

• Gas Turbine • Jet Engine• Combined Cycle &

Co-generator• Geothermal


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


Cause Codes for Internal Use

• Document specific demand periods versus “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 are Amplification Codes?

• Alpha character to describe the failure mode or reason for failure (Appendix J)

• Located in blank column next to cc.• Used by CEA and IAEA as modifiers to codes for many

years.• Increases the resources of cause codes without adding

new codes.• Many same as Failure Mechanisms (Appendix H)• Required for U1 events only; strongly recommended for

all other events.


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

• Contribution Codes (voluntary)1 Primary cause of event – there can only be one primary

cause for forced outages. There can be multiple primary causes for PO and MO events only.

2 Contributed to primary cause of event – contributed but not primary.

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.)

• 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.


Primary Event Cause (cont.)

• Time: Work Started/Time: Work Ended (voluntary) Uses 24 hour clock and looks at event start & end dates &

times. • Problem Alert (voluntary)• Man Hours Worked (voluntary)• Verbal Description (voluntary but encouraged)

Most helpful information is in the verbal descriptions IF they are completed correctly.


Types of Failures (III-34, App. H)

• Erosion• Corrosion• Electrical• Electronic

• Mechanical• Hydraulic• Instruments• Operational

(Same as Amplification Codes) (voluntary)


Typical Contributing Factors (voluntary)

• Foreign/Wrong Part• Foreign/Incorrect

Material• Lubrication Problem• Weld Related• Abnormal Load• Abnormal Temperature

• Normal Wear• Particulate

Contamination• Abnormal Wear• Set Point Drift• Short/Grounded• Improper Previous

Repair


Typical Corrective Actions (voluntary)

• Recalibrate• Adjust• Temporary Repair• Temporary Bypass• Redesign• Modify• Repair Part(s)

• Replace Part(s)• Repair Component(s)• Reseal• Repack• Request License

Revision


Method 2

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


Additional Causes of Event (voluntary)

• Same layout as primary outage causes• Used to report factors contributing to the cause of

event, additional work, factors affecting startup/ramp down

• Up to 46 additional repair records allowed


Expanded Data Reporting (III-36-38, App. H) (voluntary)

• For gas turbines and jet engines Optional but strongly encouraged

• Failure mechanism (columns 50-53) Same as Amplification Codes

• Trip mechanism (manual or auto) (column 54)• Cumulative fired hours at time of event (columns 55-

60)• Cumulative engine starts at time of event (columns

61-65)


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

1801 - Minor Boiler overhaul 720 hours or less


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?


Quick Quiz (cont.)

Answer:• Major Turbine overhaul

Cause Code 4400 Contribution Code 1

• High-Pressure Turbine reblading Cause Code 4012 Contribution Code 1


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?


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.


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?


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


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?


Quick Quiz (cont.)

Answer:1. The start time of the event is after the end time.2. Looking at the description of the event, the better

cause code would be 1460 (fouling of ID Fan) rather than just ID Fan general code 1455.


Question & Answer


GADS Editing Program


GADS Edits

• Purpose of Edits Sanity check of event records (dates, times, cause codes by

unit type, amp codes, overlapping events, etc. Sanity and agreement of data on events and performance

records (+/- 0.01 hours) With limits of design specifications (commercial date, MW

size, type of unit, etc) GADS will return error reports/clean data reports.• List of edit checks available for the asking• Report as GADS requires! Don’t skip reporting records

to make deadlines. (Kick records out).


Review of Standard Terms and Definitions Used by the Electric Industry


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




“Scheduled” - preventive

From the Unit State Chart …


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

1. Time-based All events Without Outside Management Control (OMC)

2. Capacity- or Energy-based All events Without Outside Management Control (OMC)


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. Now used in GADS reports and pc-GAR software.

• 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 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 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?”

• 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


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


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.oPO – “Well in Advance”oMO - Beyond the next weekend.

A measure of the unit’s unavailability due to planned or maintenance outages.

The lower the SOF, the better.


SOF = 100% x (POH + MOH)PH

Scheduled Outage Factor (SOF)


Other Outage Factors

Maintenance Outage Factor (MOF)

Planned Outage Factor (POF)

POF = 100% x (POH)PH

MOF = 100% x (MOH)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)]


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 NCF and NOF

EAF NCF NOFFossil Units, Coal, All Sizes 83.62 69.36 84.10Fossil Units, Oil, All Sizes 83.52 11.70 44.40Fossil Units, Gas, All Sizes 86.12 12.73 37.41Nuclear, All Sizes 88.81 89.58 99.03Gas Turbines, All Sizes 90.07 2.50 66.93Combined Cycle Blocks 87.22 37.35 73.91Hydro Units, All Sizes 85.60 40.62 69.14

(GADS 2006-2010 Data)


Comparing AF/EAF/NCF/NOF

NOF > NCF

AF > EAF > NCF

(Because SH is normally less than PH. What would be the exception?)

(What would cause these 3 numbers to be equal? What is its likelihood of occurring?)


Time-based Equations – Rates


Forced Outage Rate (FOR)

• 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

o (reserve shutdowns and scheduled outage influence it) Best used to compare similar loads:

obase load vs. base loado cycling vs. cycling

The lower the FOR, the better.


Forced Outage Rate (FOR)

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%


Equivalent Forced Outage Rate (EFOR)

• 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.



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%


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!


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.


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 >0 >0 Applicable Applicable

1 0 >0 >0 Cannot be determined

Cannot be determined

2 0 0 >0 Cannot be determined


3 0 >0 0 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 0 Cannot be determined


Base case is normal. Cases 4, 5, 6: Computed FORd, EFORd are valid.


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.


Other 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



• 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.


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 EAF

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


Weighted EAF

Fossil-steam units in USA; 2004-2008


WEAF and Age of Fossil Units

All Sizes and FuelsFossil-steam units in USA 1982-2008


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 = 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%


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)


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.• Software for modifying your generating units are

available now. Voluntary! Ask Mike Curley for files of your own units.


Closing Comments


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]


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.


Question & Answer

Contact:

Mike CurleyManager of GADS [email protected]

gads 101 data reporting workshop

Documents

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