NERC GADS 101 Data Reporting Workshop

G. Michael CurleyManager of GADS ServicesOctober 27-29, 2010

NERC GADS 101NERC GADS 101Data Reporting WorkshopData Reporting Workshop

GADS Services Staff

• Mike Curley – Manager of GADS Services

• Joanne Rura – GADS Services Coordinator

• Ronald Niebo – Reliability Assessment and Performance Analysis Coordinator

Please stand and introduce yourselves

• Your name, company, and experience with GADS

WelcomeWelcome

Overview of Attendees at this ConferenceOverview of Attendees at this Conference

Representatives of:

• Generating companies (IOU, IPPs, Government, etc)

• Consultants

• Insurance

• ISOs

What’s in the folder?What’s in the folder?

Agenda

List of attendees (as of October 20, 2010)

Changes to the 2011 DRI

Slides for GADS 101 Data Reporting Workshop

Slides for GADS Wind Data Reporting Workshop

Slides for Benchmarking Seminar

Slides for pc-GAR and pc-GAR MT Workshop

Slides for Unit Design Data Entry Program

Flash drive4

What’s on the flash drive?What’s on the flash drive?

Same as the folder plus … GADS Data Reporting Instructions (effective January 1, 2011)

GADS Data Editing Program

GADS Services Pricing Schedule

pc-GAR and pc-GAR MT Demo Software

pc-GAR Order Forms

GADS Wind Turbine Generation Data Reporting Instructions

GADS Wind Generation Data Entry Software

WEC Studies

AgendaAgenda

Introduction and welcoming remarks

• What is NERC?

• What is GADS?

Fundamentals on the three GADS Databases

DesignWhat makes up the design database?

Event What are the elements of the event database?

PerformanceWhat are the elements of the performance database?

Agenda (cont.)Agenda (cont.)

IEEE 762 Equations and their meanings

• What are the equations calculated by GADS?

• What are they trying to tell you?

• Review of standard terms and equations used by the electric industry.

Data release policies

What’s new with GADS?

Closing Comments

NERC is the ERO

NERC BackgroundNERC Background

NERC started in 1968.

NERC chosen as the ERO for the US in 2006. Started developing the “Rules of Procedure” to manage the bulk power supply.

BPS consists of the transmission and generation facilities.

NERC changed from “council” to “corporation” in January 2007.

From 2007 to now, NERC became the ERO of 6 of the 10 Canadian Provinces.

Energy Policy Act of 2005Energy Policy Act of 2005

Signed by President Bush in August 2005

The reliability legislation amends Part II of the Federal Power Act to add a section 215 making reliability standards for the bulkpower 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 2005Energy Policy Act of 2005

“Bulk-power System” means the facilities and control systems necessary for operating an interconnected electric energy transmission network (or any portion thereof) and electric energy from generation facilities needed to maintain transmission system reliability. The term does not include facilities used in the local distribution of electric energy.

About NERCAbout NERC

Develop & enforce reliability standards

Analyze system outages and near-misses & recommend improved practices

Assess current and future reliability

International regulatory authority for electric reliability in North America

Meeting Demand in Real TimeMeeting Demand in Real Time

Typical Daily Demand Curve

Base Load

Intermediate Load

Peak Load

Operating Reserves

Energy: Electricity Produced over Time

Capacity: Instantaneous measure of electricity available at peak

About NERC: Regional Entities (RE)About NERC: Regional Entities (RE)

Florida Reliability Coordinating Council

Midwest Reliability Organization

Northeast Power Coordinating Council

ReliabilityFirst Corporation

SERC Reliability Corporation

Southwest Power Pool, Reliability Entity

Texas Regional Entity

Western Electricity Coordinating Council

What does NERC do?What does NERC do?

Sets reliability standards (96 in place; 24 being reviewed)

Monitors compliance with reliability standards

Provides education and training resources

Conducts reliability assessments

Facilitates reliability information exchange

Supports reliable system operation and planning

Certifies reliability organizations and personnel

Coordinates security of bulk electric system

• Cyber attacks

• Pandemics

• Geomagnetic disturbances

One of the first orders of business…One of the first orders of business…

Create a transmission database

• Transmission Availability Data System (TADS)

• 200 kV and above.

• Currently 2 years of data in TADS

Work now…Work now…

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

GADS Task ForceGADS Task Force

Talked about mandatory GADS reporting for many years.

In June 2010, the NERC Planning Committee (PC) approved a task force to determine if GADS should be mandatory and to what level.

• About 77% of the installed capacity already report to GADS.

• Voluntary database now.

To date, the GADSTF is recommending mandatory reporting of GADS data.

Rules of Procedure: Section 1600Rules of Procedure: Section 1600OverviewOverview

NERC’s authority to issue a mandatory data request in the U.S. is contained in FERC’s rules. Volume 18 C.F.R. Section 39.2(d) states: “Each user, owner or operator of the Bulk-Power System within the United States (other than Alaska and Hawaii) shall provide the Commission, the Electric Reliability Organization and the applicable Regional Entity such information as is necessary to implement section 215 of the Federal Power Act as determined by the Commission and set out in the Rules of Procedure of the Electric Reliability Organization and each applicable Regional Entity.”

Rules of Procedure: Section 1600Rules of Procedure: Section 1600Request DetailsRequest Details

A complete data request includes:• a description of the data or information to be requested, how the

data or information will be used, and how the availability of the data or information is necessary for NERC to meet its obligations under applicable laws and agreements

• a description of how the data or information will be collected and validated

• a description of the entities (by functional class and jurisdiction) that will be required to provide the data or information (“reporting entities”)

• the schedule or due date for the data or information

• a description of any restrictions on disseminating the data or information (e.g., “confidential,” “critical energy infrastructure information,” “aggregating” or “identity masking”)

• an estimate of the relative burden imposed on the reporting entities to accommodate the data or information request

NERC Approval CommitteesActingSubgroup

Rules of Procedure: Section 1600Rules of Procedure: Section 1600ProcedureProcedure

Draft Data

Request

Submit Data

Request to DCS

Submit Data

Request to PC

Not Approved

SubmitData

Request

FERC Comment Period

File DataRequest

(21 Days)

Public Comment Period

Post DataRequest

(45 Days)

Collect,Respond, &

PostComments

FinalizeData

Request

NERC Board of Trustees

SubmitFinal Data

Request

Data RuleIn Effect

Affected Parties

Appeal(30 Days)

Approved

Not Approved

Rules of Procedure: Section 1600Rules of Procedure: Section 1600LimitationsLimitations

NERC Registered Entities

Subject to FERC Rules

• Data Request does not carry the same penalties to non-U.S. entities.

• However, all NERC Registered Entities, regardless of their country of origin, must comply with the NERC Rules of Procedure, and as such, are required to comply with Section 1600

What if a GO doesn’t comply?What if a GO doesn’t comply?

Possible NERC actions:

• From Rule 1603: “Owners, operators, and users of the bulk power system registered on the NERC Compliance Registry shall comply with authorized requests for data and information.” The data request must identify which functional categories are required to comply with the request. In this case, it presumably would be Generation Owners.

• 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.

• 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 1600.

• Under section 215 of the Federal Power Act, FERC has jurisdiction over all users, owners, and operators of the bulk power system within the United States.

• FERC could treat a failure by a U.S. entity to comply with an approved data request as a violation of a rule adopted under the Federal Power Act using its enforcement mechanisms in Part III of the FPA.

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 RulesGADS vs. ISO Data Collection Rules

Currently, GADS sets data collection rules for use on a national basis; each ISO can set the rule for data collection within their jurisdiction.

Here are special rules that GADS suggests for hydro units.

• As of August 5, 2008 we considered a draft of the rules.

• A more “final set of rules” is now Appendix M of the GADS Data Reporting Instructions issued January 2010.

One recommendation of GADSTF is one set of rules for all (coordination between GADS and ISOs).

More information?More information?

Please visit our website: www.nerc.com

Most information is open to the public.

Question & Answer

What is GADS?What is GADS?

A - Availability

S - System

G - Generating

D - Data

What is GADS?What is GADS?

Analyze the past (1982-2009)

• Conduct special studies like high impact/low probability (HILP) studies

• Perform benchmarking services

Monitor the present (2010 data)

• Track current unit performance

Assess the future

• Predict the future performance of units

Example – Benchmarking – Distributions Example – Benchmarking – Distributions

[Fossil-steam units 200-400MW; Coal fuel; 6,500+ Service Hours/Yr.; 2005-2009; (79 units from 73 companies)] 33

Example – Benchmarking – Top ProblemsExample – Benchmarking – Top Problems

[Fossil-steam units 200-400MW; Coal fuel; 6,500+ Service Hours/Yr.; 2005-2009; (79 units from 73 companies)] 34

What is meant by “Availability?”What is meant by “Availability?”

GADS maintains a history of actual generation, potential generation and equipment outages.

Not interested in dispatch requirements or needs by the system!

** If the unit is not available to produce 100% load, we want to know why!

Monitor the PresentMonitor the Present

Generator “B”

Generator “A”

Generator “C”

Generator “D”

Generator “E”

5,800+ generating units including 2 international affiliates.

International GADS UsersInternational GADS Users

Malaysia *

Ireland *

Brazil *

India *

Peoples Republic of China

New Zealand

South Korea

Parts of S. America

* Are or soon will be reporting outage data to GADS.

GADS 2009 Data ReportingGADS 2009 Data Reporting

1990 1992 1994 1996 1998 2000 2002 2004 2006 2008

5,874 units reported in 2009, 0.9% increase in thenumber of units reporting over 2008!

Why GADS?Why GADS?

Provide NERC committees with information on availability of power plant for analyzing grid reliability and national security issues.

Provide energy marketers with data on the reliability of power units.

Assist planning of future facilities.

Help in setting goals for production and maintenance.

Why GADS?Why GADS?

Evaluating new equipment products and plant designs.

Assisting in prioritizing repairs for overhauls.

Help planners with outage down timing and costs.

Provide insights on equipment problems and preventative outages.

Why GADS?Why GADS?

Benchmarking existing units to peers.

Provide a source of backup data for insurance, governmental inquiries and investigations, and lose of hard drives.

Working to find answers to questions not asked.

• Economic dispatch records

• Generation owners in several regions

• Track units bought and sold

Question & Answer

The GADS Data MonsterThe GADS Data Monster

The GADS DatabasesThe GADS Databases

Design – equipment descriptions such as manufacturers, number of BFP, steam turbine MW rating, etc.

Performance – summaries of generation produced, fuels units, start ups, etc.

Event – description of equipment failures such as when the event started/ended, type of outage (forced, maintenance, planned), etc.

Design Data Reporting (Section V)

Why collect design data?Why collect design data?

For use in identifying the type of unit (fossil, nuclear, gas turbine, etc).

Allows selection of design characteristics necessary for analyzing event and performance data.

Provides the opportunity to critique past and present fuels, improvements in design, manufacturers, etc.

Unit Types (Appendix C)Unit Types (Appendix C)

Unit Type Coding Series

Fossil (Steam)(use 600-649 if additional numbers are needed)

100-199

Nuclear 200-299

Combustion Turbines(Use 700-799 if additional numbers are needed)

300-399

Diesel Engines 499-499

Hydro/Pumped Storage(Use 900-999 if additional numbers are needed)

500-599

Fluidized Bed Combustion 650-699

Miscellaneous(Multi-Boiler/Multi-Turbine, Geothermal, Combined Cycle Block, etc.)

800-899

Minimum Design Data for EditingMinimum Design Data for Editing

Utility (Company) Code

Unit Code

NERC Region

Date of commercial operation

• Reaching 50% of its generator nameplate MW capacity

• Turned over to dispatch (enters “active state”)

Nameplate rating of unit (permanent)

State location

Design Data FormsDesign Data Forms

Forms are located in Appendix E

Complete forms when:

• Utility begins participating in GADS

• Unit starts commercial operation

• Unit’s design parameters change such as a new FGD system, replace the boiler, etc.

Example of Design Data FormExample of Design Data Form

Performance Reporting (Section IV)

Why collect performance records?Why collect performance records?

Collect generation of unit on a monthly basis.

Provide a secondary source of checking event data.

Allows analysis of fuels

Performance ReportPerformance Report

“05” Format (new)

• More accurate with 2 decimal places for capacities, generation and hours.

• Collects inactive hours (discussed later)

• As of January 1, 2010, GADS only accepts the new format.

Performance RecordsPerformance Records

General Overview:

Provides summary of unit operation during a particular month of the year.

• Actual Generation

• Hours of operation, outage, etc.

Submitted quarterly for each month of the year.

• Within 30 days after the end of the quarter

Unit IdentificationUnit Identification

Record Code – the “05” uniquely identifies the data as a performance report (required)

Utility (Company) Code – a three-digit code that identifies the reporting organization (required)

Unit Code – a three-digit code that identifies the unit being reported. This code also distinguishes one unit from another in your utility (required)

Unit Identification (cont.)Unit Identification (cont.)

Year – is the year of the performance record (required)

Report Period – is the month (required)

Report Revision Code – shows changes to the performance record (required)

• Original Reports (0)

• Additions or corrections (1, 2,…9)

• Report all records to a performance report if you revise just one of the records.

Unit GenerationUnit Generation

Six data elements

Capacities and generation of the unit during the report period.

Can report both gross and net capacities.

• Net is preferred

• Missing Net or Gross capacities will be calculated!

Unit Generation (cont.)Unit Generation (cont.)

Gross Maximum Capacity (GMC)• Maximum sustainable capacity (no derates)

• Proven by testing

• Capacity not affected by equipment unless permanently modified

Gross Dependable Capacity (GDC)• Level sustained during period without equipment, operating

or regulatory restrictions

Gross Actual Generation• Power generated before auxiliaries

Unit Generation (cont.)Unit Generation (cont.)

Net Maximum Capacity (NMC)• GMC less any capacity utilized for unit’s station services (no

derates).

• Capacity not affected by equipment unless permanently modified.

Net Dependable Capacity (NDC)• GDC less any capacity utilized for that unit’s station services.

Net Actual Generation• Power generated after auxiliaries.

• Can be negative if more aux than gross!

Gas Turbine/Jet CapacitiesGas Turbine/Jet Capacities

GT & Jets capacities do not remain as constant as fossil/nuclear units.

ISO standard for the unit (STP -- based on environment) should be the GMC/NMC measure.

Output less than ISO number is unit GDC/NDC.

Average capacity number for month is reported to GADS

Effect of Ambient TemperatureEffect of Ambient Temperature

Maximum and Dependable CapacityMaximum and Dependable Capacity

What is the difference betweenMaximum and Dependable?

• GMC - GDC = Ambient Losses

• NMC - NDC = Ambient Losses

Missing Capacity Calculation!Missing Capacity Calculation!

If any capacity (capacities) is (are) not reported, the missing capacities will be calculated based on all reported numbers.

For example, if only the NDC is reported and the NDC = 50, then:

• NDC = NMC = 50

• GMC = NMC times (1 + factor)

• GDC = NDC times (1 + factor)

• GAG = NAG times (1 + factor)

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 QuizQuick Quiz

Question:

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

Quick Quiz (cont.)Quick Quiz (cont.)

Answer:

Leave the field blank or place asterisks (*) in the gross max, gross dependable, and gross generation fields. The editing program recognizes the blank field or the * and will look only to the net sections for data.

Unit LoadingUnit Loading

Typical Unit Loading Characteristics

Code Description

1 Base loaded with minor load-following at night and on weekends

2 Periodic startups with daily load-following and reduced load nightly

3 Weekly startup with daily load-following and reduced load nightly

4 Daily startup with daily load-following and taken off-line nightly

5 Startup chiefly to meet daily peaks

6 Other (see verbal description)

7 Seasonal Operation (winter or summer only)

Attempted & Actual Unit StartsAttempted & Actual Unit Starts

Attempted Unit Starts

• Attempts to synchronize the unit

• Repeated failures for the same cause without attempted corrective actions are considered a single start

• Repeated initiations of the starting sequence without accomplishing corrective repairs are counted as a single attempt.

• For each repair, report 1 attempted starts.

Actual Unit Starts

• Unit actually synchronized to the grid70

Attempted & Actual Unit Starts (cont.)Attempted & Actual Unit Starts (cont.)

If you report actual start, you must report attempted.

If you do not keep track then:

• Leave Starts Blank

• GADS editor will estimate both attempted and actual starts based on event data.

The GADS program also accepts “0” in the attempts field if actual = 0 also.

Unit Time InformationUnit Time Information

Service Hours (SH)

• Number of hours synchronized to system

Reserve Shutdown Hours (RSH)

• Available for load but not used (economic)

Unit Time Information (cont.)Unit Time Information (cont.)

Pumping Hours

• Hours the hydro turbine/generator operated as a pump/motor

Synchronous Condensing Hours

• Unit operated in synchronous mode

• Hydro, pumped storage, gas turbine, and jet engines

Available Hours (AH)

• Sum of SH+RSH+Pumping Hours+ synchronous condensing hours

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

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?

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.

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%}

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 FuelPrimary Fuel

Can report from one to four fuels

Primary (most thermal BTU) fuel

Not required for hydro/pumped storage units

Required for all other units, whether operated or not

Primary Fuel (cont.)Primary Fuel (cont.)

Fuel Code (required)

Quantity Burned (optional)

Average Heat Content (optional)

% Ash (optional)

%Moisture (optional)

% Sulfur (optional)

% Alkalis (optional)

Grindability Index (coal only)/ % Vanadium and Phosphorous (oil only) - (optional)

Ash Softening Temperature (optional)84

Fuel CodesFuel Codes

Code Description Code Description

CC Coal PR Propane

LI Lignite SL Sludge Gas

PE Peat GE Geothermal

WD Wood NU Nuclear

OO Oil WM Wind

DI Distillate oil SO Solar

KE Kerosene WH Waste Heat

JP JP4 or JP5 OS Other – Solid (Tons)

WA Water OL Other – Liquid (BBL)

GG Gas OG Other – Gas (Cu. Ft.)

Fuel Codes

Question & Answer

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?

Answer:

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

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?

Answer:

There is no derating!

• NMC – NDC = 100 – 100 = 0 (zero)

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?

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?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” FactorThe “Ouch” Factor

Non-IEEE or any other term

A description of what is the maximum information you can gather from a power generator before they yell “ouch!”

GADS is at the maximum Ouch Factor at this time.

Event IdentificationEvent Identification

Record Code – the “07” uniquely identifies the data as an event report (required)

Utility (Company) Code – a three-digit code that identifies the reporting organization (required)

Unit Code – a three-digit code that identifies the unit being reported. This code also distinguishes one unit from another in your utility (required)

Event Identification (cont.)Event Identification (cont.)

Year – the year the event occurred (required)

Event Number – unique number for each event (required)

• One event number per outage/derating

• Need not be sequential

• Events that continue through multiple months keeps the originally assigned number

One Event for One OutageOne Event for One Outage

Month 1 Month 2 Month 3

Event 1 Event 1 Event 1

Event 1

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?

Answer:

• 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 GADS is a DYNAMICDYNAMIC SystemSystem

Make as many changes as you want,

as many times as you want,

whenever you want.

Report Year-to-date!Report Year-to-date!

Report all data year-to-date with the revision code zero “0” again.

• If any other changes were made, the reporters and NERC databases would always be the same.

• It is easier and better to replace the entire database then to append one quarter to the next.

Report Revision Code – shows changes to the event record (required)

• Original Reports (0)

• Additions or corrections (1, 2,…9)

• Report all records to a performance report if you revise just one of the records.

Event Type – describes the event experienced by the unit (required)

• Inactive

• Active103

Unit StatesUnit States

Unit States – InactiveUnit States – Inactive

Unit States – Inactive (cont.)Unit States – Inactive (cont.)

Inactive

• Deactivated shutdown (IEEE 762) as “the State in which a unit is unavailable for service for an extended period of time for reasons not related to the equipment.”

• IEEE and GADS interprets this as Inactive Reserve, Mothballed, or Retired

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 – ActiveUnit States – Active

Event Type (required -- 17 choices)

• Two-character code describes the event (outage, derating, reserve shutdown, or noncurtailing).

EVENT TYPES

OUTAGES DERATINGS

PO – Planned PD – Planned

PE – Planned Extension DP – Planned Extension

MO – Maintenance D4 – Maintenance

ME – Maintenance Extension DM – Maintenance Extension

SF – Startup Failure D1 – Forced - Immediate

U1 – Forced - Immediate D2 – Forced - Delayed

U2 – Forced - Delayed D3 – Forced - Postponed

U3 – Forced Postponed

RS – Reserve Shutdown

NC – Non Curtailing

Unit States – Active (cont.)Unit States – Active (cont.)

What is an outage?

• An outage starts when the unit is either desynchronized (breakers open) from the grid or when it moves from one unit state to another

• An outage ends when the unit is synchronized (breakers are closed) to the grid or moves to another unit state.

• In moving from one outage to the next, the time (month, day, hour, minute) must be exactly the same!

From the Unit States DiagramFrom the Unit States Diagram

“Unplanned”

Forced + Maintenance + Planned

From the Unit States DiagramFrom the Unit States Diagram

“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.115

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 00:00PE or ME on January 1 at 00:00

Edit program checks to make sure an extension (PE or ME) is preceded by a PO or MO event.

Create a PO or MO event for one minute before the PE or ME.

• Start of Event: 01010000

• End of Event: 01010001

Forced-type Outages

• Immediate (U1) – requires immediate removal from service, another Outage State, or a Reserve Shutdown state. This type of outage usually results from immediate mechanical/electrical/hydraulic control systems trips and operator-initiated trips in response to unit alarms.

• Delayed (U2) – not required immediate removal from service, but requires removal within six (6) hours. This type of outage can only occur while the unit is in service.

• Postponed (U3) – postponed beyond six (6) hours, but requires removal from service before the end of the next weekend 119

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 OutageExample #1 – Simple Outage

Event Description:

On January 3 at 4:30 a.m., Riverglenn #1 tripped off line due to high turbine vibration.

The cause was the failure of an LP turbine bearing (Cause Code 4240).

The unit synchronized on January 8 at 5:00 p.m.

Example #1 – Simple OutageExample #1 – Simple Outage

0 1 2 3 4 5 6

Jan 3 @ 0430 Jan 8 @ 1700

Forced Outage CC 4240

Capacity (MW)

Scenario #1: FO or MO?Scenario #1: FO or MO?

There was a tube leak in the boiler 4 days before the scheduled PO. (Normal repair time is 36 hours.)

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

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

What type of outage is this?

Answer: First 36 hours to fix tube leak (U2) then change to PO. Why?

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!

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.

Answer: MO. Why?

Answer: The unit could have stayed on line until the end of the next weekend if required.

Scenario #3: FO or MO? Scenario #3: FO or MO?

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

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

Answer: FO. Why?

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? Scenario #4: FO or RS?

It’s Monday. Combined cycle had a HRSG tubeleak and must come off line now. It is 2x1 with no by-pass capabilities.

Dispatch said CC was not needed for remainder of week.

Management decided to repair the unit on regular maintenance time. Over the next 36 hours, the HRSG was repaired. Normal HRSG repairs take 12 hours of maintenance time.

What type of outage is this and for how long? 132

Scenario #4: FO or RS? Scenario #4: FO or RS?

It’s Monday. Combined cycle had a HRSG tube leak and must come off line now. It is 2x1 with no by-pass capabilities.

Dispatch said CC was not needed for remainder of week.

Management decided to repair the unit on regular maintenance time. Over the next 36 hours, the HRSG was repaired. Normal HRSG repairs take 12 hours of maintenance time.

What type of outage is this and for how long?

Answer: FO as long as the unit is not operable – full 36 hours. Then RS (CA).

Scenario #5: PE or FO?Scenario #5: PE or FO?

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

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

What type of outage is the extra 3 days?

Answer: SE. Why?

Answer: ESP work was part of the original scope of work.

Scenario #6: ME or FO?Scenario #6: ME or FO?

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

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

What type of outage is the extra 12 hours?

Answer: FO. Why?

Answer: No part of original scope and delayed startup by 12 hours.

Scenario #7: PO or FO?Scenario #7: PO or FO?

During the 4 week PO, mechanics discovered ID fan blades needed replacement (outside the scope).

Parts were ordered and ID fan was repaired within the 4 week period. No delays in startup.

Does the outage change from PO to FO and then back to PO due to unscheduled work?

Answer: remains PO for full time. Why?

Answer: work completed with scheduled PO time.

More Examples?More Examples?

Appendix G – Examples and Recommended Methods

Reporting Outages to the Generating AvailabilityData System (GADS)

A Word of Experience …A Word of Experience …

IEEE definitions are designed to be guidelines and are interpreted by GADS.

We ask all reporters to follow the guidelines so that uniformity is reporting and resulting statistics.

If a unit outage is determined to be a MO, it is an MO by IEEE Guidelines.

• If a unit needs to come off and is not allowed to, more damage to the equipment and longer outages will be the result. (Investigation from Southern Co.)

Testing Following OutagesTesting Following Outages

On-line testing (synchronized)

• In testing at a reduced load following a PO, MO, or FO, report the derating as a PD, D4 or the respective forced-type derating

• Report all generation

Off-line testing (not synchronized)

• Report testing in “Additional Cause of Event or Components Worked on During Event”

• Can report as a separate event

Black Start TestingBlack Start Testing

A black start test is a verification that a CT unit can start without any auxiliary power from the grid and can close the generator breaker onto a dead line or grid.

To set up the test, you isolate the station from the grid, de-energize a line, and then give the command for the CT to start. If the start is successful, then you close the breaker onto the dead line. Once completed, you take the unit off, and re-establish the line and aux power to the station.

You coordinate this test with the transmission line operator, and it is conducted annually.

Black Start Testing (cont.)Black Start Testing (cont.)

GADS Services surveyed the industry and it was concluded that:

• It is not an outside management control event.

• It can be a forced, maintenance or planned event.

• Use the new cause code 9998.

Any questions about outages?

Unit States (Deratings)Unit States (Deratings)

What is a derate?

• A derate starts when the unit is not capable of reaching 100% capacity.

• A derate ends when the equipment is either ready for or put back in service.

• An capacity is based on the capability of the unit, not on dispatch requirements.

• More than one derate can occur at a time.

Unit States (Deratings)Unit States (Deratings)

Report a derate or not?

• If the derate is less than 2% NMC AND last less than 30 minutes, then it is optional whether you report it or not.

• All other derates shall be reported!

Report a 1-hour derate with 1% reduction

Report a 15-minute derate with a 50% reduction.

Unit Capacity LevelsUnit Capacity Levels

Deratings

• Ambient-related Losses are not reported as deratings - report on Performance Record (NMC-NDC)

• System Dispatch requirements are not reported

Unit States – ActiveUnit States – Active

Forced Deratings

• Immediate (D1) – requires immediate reduction in capacity.

• Delayed (D2) – does not require an immediate reduction in capacity but requires a reduction within six (6) hours.

• Postponed (D3) – can be postponed beyond six (6) hours, but requires reduction in capacity before the end of the next weekend.

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 Capacity

Seasonal Derating = Maximum Capacity - Dependable Capacity

Dependable Capacity

Basic Planned DeratingPlannedDerating Extended Planned Derating

Unit Derating= D 1

D 2 UnplannedDerating

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 DeratingExample #2 – Simple Derating

Event Description:

On January 10 at 8:00 a.m., Riverglenn #1 reduced capacity by 250 MW due to a fouled north air preheater, leaving a Net Available Capacity (NAC) of 450 MW.

Fouling began two days earlier, but the unit stayed on line at full capacity to meet load demand.

Repair crews completed their work and the unit came back to full load [700 MW Net Maximum Capacity (NMC)] on January 11 at 4:00 p.m. The Net Dependable Capacity (NDC) of the unit is also 700 MW.

Example #2 – Simple DeratingExample #2 – Simple Derating

0 1 2 3 4 5 6

Jan 10 @ 0800 Jan 11 @1600

Derating

Unit DeratingsUnit Deratings

Deratings that vary in magnitude

• New event for each change in capacity or,

• Average the capacity over the full derating time.

Unit Deratings Unit Deratings

Overlapping Deratings• All deratings are additive unless shadowed by an outage or

larger derating.

• Shadowed derating are Noncurtailing on overall unit performance but retained for cause code summaries.

• Can report shadowed deratings

• Deratings during load-following must be reported.

• GADS computer programs automatically increase available capacity as derating ends.

• If two deratings occur at once, choose primary derating; other as shadow.

Example #3 - Overlapping Deratings Example #3 - Overlapping Deratings Second Starts & Ends Before First (G-3A)Second Starts & Ends Before First (G-3A)

Event Description:

Riverglenn #1 had an immediate 100 MW derating onMarch 9 at 8:45 a.m. due to a failure of the ‘A’ pulverizer feeder motor. Net Available Capacity (NAC) is 500 MW.

At 10:00 a.m. the same day, another 100 MW (NAC = 500 MW) loss occurs with the failure of ‘B’ pulverizer mill. Failure of the ‘B’ mill is repaired after 1 hour when a foreign object is removed from the mill.

The ‘A’ motor is repaired and returned to service on March 9 at 6:00 p.m.

Example #3 - Overlapping Deratings Example #3 - Overlapping Deratings Second Starts & Ends Before First (G-3A)Second Starts & Ends Before First (G-3A)

0 1 2 3 4 5 6

3/9@:0845 3/9@1800

Capacity (MW)

Forced Derating CC 0250

D1 CC0320

3/9@1000 3/9@1100

Dominant Derating CodeDominant Derating Code

All deratings remain as being additive unless modifier marked as “D”

Derating modifier marks derating as being dominate, even if another derating is occurring at the same time.

No affect on unit statistics.

Affects cause code impact reports only.

Example #4 - Overlapping DeratingExample #4 - Overlapping Derating(2nd is Shadowed by the 1st) (G-3B)(2nd is Shadowed by the 1st) (G-3B)

Event Description:

Riverglenn #1 had a D4 event on July 3 at 2:30 p.m. from a condenser maintenance item that reduced the NAC to 590 MW. Fouled condenser tubes (tube side) were the culprit. Maintenance work began on July 5 at 8 a.m. and the event ended on July 23 at 11:45 a.m.

On July 19 at 11:45 a.m., a feedwater pump tripped, reducing the NAC and load to 400 MW. This minor repair to the feedwater pump was completed at noon that same day. 164

Example #4 - Overlapping Derating Example #4 - Overlapping Derating (1st is Shadowed by the 2nd) with Dominant Code(1st is Shadowed by the 2nd) with Dominant Code

0 1 2 3 4 5 6

7/3@1430 7/23@1145

Capacity (MW)D4 CC 3112

D1 CC 3410

7/19@1115 7/19@1200

Dominant Derating CodeDominant Derating Code

700Capacity (MW)

D4 CC 3112

D1 CC3410

700Capacity (MW)

D4 CC 3112

D1 CC3410

Event #1 Event #2

Event #1 Event #3

Event #2

Without Dominant Derating Code

With Dominant Derating Code

3 events to cover 2 incidents

2 events to cover 2 incidents166

Dominant Derating Code (cont.)Dominant Derating Code (cont.)

How do you know if a derating is dominant?

• If you’re not sure, ask!

Control room operator

Plant engineer

• If you don’t mark it dominant, the software will assume it is additive. That can result in inaccurate reporting.

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 4 171

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

Derating –Event 4 takes the dominant position.

Derating –Event 4 172

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 StatesOther Unit States

Reserve Shutdown – unit not synchronized but ready for startup and load as required.

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

Rata testing?

Generator Doble testing?

Question & Answer

Event MagnitudeEvent Magnitude

Impact of the event on the unit

4 elements per record:

• Start of event

• End of event

• Gross derating level

• Net derating level

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

Maximum Capacity

Seasonal Derating = Maximum Capacity - Dependable Capacity

Dependable Capacity

Basic Planned DeratingPlannedDerating Extended Planned Derating

Unit Derating= D 1

D 2 UnplannedDerating

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 …181

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.)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.)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 ClockUsing the 24-hour Clock

If the event starts at midnight, use:

• 0000 as the start hour and start time

If the event ends at midnight, use:

• 2400 as the end hour and end time

Event Transitions (Page III-24)Event Transitions (Page III-24)

There are selected outages that can be back-to-back; others cannot.

Related events are indicated by a “yes”; all others are not acceptable.

Event Transitions (cont.)Event Transitions (cont.)

TO FROM U1 U2 U3 SF MO PO ME PE RS

U1 - Immediate Yes No No Yes Yes Yes No No Yes

U2 – Delayed Yes No No Yes Yes Yes No No Yes

U3 – Postponed Yes No No Yes Yes Yes No No Yes

SF - Startup Failure Yes No No Yes Yes Yes No No Yes

MO – Maintenance Yes No No Yes Yes Yes Yes No Yes

PO – Planned Yes No No Yes No Yes No Yes Yes

ME – Maintenance Extension

Yes No No Yes No No Yes No Yes

PE – Planned Extension Yes No No Yes No No No Yes Yes

RS – Reserve Shutdown Yes No No Yes Yes Yes No No Yes

Allowable Event Type Changes

Question & Answer

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?

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?

Answer:

Change the U2 to an SF

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?

Answer:

No. Why?

Standard operating procedure. By NERC’s standards, it is not a derate.

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?

Answer:

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

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?

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 CausePrimary Event Cause

Details of the primary cause of event

• What caused the outage/derate?

• May not always be the root cause

Primary Event CausePrimary Event Cause

Described by using cause code

• 4-digit number (See Appendix B)

• 1,600+ cause codes currently in GADS

• Points to equipment problem or cause, not a detailed reason for the outage/derate!

• Set of cause codes for each type of unit.

Cause codes for fossil-steam units only

Cause codes for hydro units only

Set of Cause Codes for Each Unit TypeSet of Cause Codes for Each Unit Type

Fossil

Fluidized Bed Fossil

Nuclear

Diesel

Hydro/Pumped Storage

Gas Turbine

Jet Engine

Combined Cycle & Co-generator

Geothermal

Set of Cause Codes for Each Unit TypeSet of Cause Codes for Each Unit Type

Example of two names, different units:

Fossil-steam

• 0580 - Desuperheater/attemperator piping

• 0590 - Desuperheater/attemperator valves

Combined cycle

• 6140 - HP Desuperheater/attemperator piping - Greater than 600 PSIG.

• 6141 - HP Desuperheater/attemperator valves

Cause Codes for Internal EconomicsCause Codes for Internal Economics

Document specific demand periods verses “average” differences for a month.

Want to calculate EAF and NCF differences for any period of time.

NOT REPORTED TO GADS!

20 cause codes (9180 to 9199) set up.

What is Amplification Code?What is Amplification Code?

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

Located in blank column next to cc.

Used by CEA and IAEA as modifiers to codes for many years.

Increases the resources of cause codes without adding new codes.

Many same as Failure Mechanisms (Appendix H)

This is voluntary but important.204

Example of Amplification CodeExample of Amplification Code

C0 = Cleaning

E0 = Emission/environmental restriction

F0 = Fouling

45 = Explosion

53 = Inspection, license, insurance

54 = Leakage

P0 = Personnel error

R0 = Fire205

Example of Amplification CodeExample of Amplification Code

Boiler (feedwater) pump packing leak.

• Cause code 3410; amp code “54”

HP Turbine buckets or blades corrosion

• Cause code 4012; amp code “F0”

Operator accidentally tripped circulating water pump

• Cause code 3210; amp code “P0”

Event Contribution CodesEvent Contribution Codes

Contribution Codes1 Primary cause of event – there can only be one primary

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

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

3 Work done during the event – worked on during event but did not initiate event.

5 After startup, delayed unit from reaching load point

Note: No codes 6 or 7 as of January 1, 1996

Event Contribution Codes (cont.)Event Contribution Codes (cont.)

Contribution Codes• Can use event contribution code 1 (Primary cause of event) on

additional causes of events during PO and MO events only and not any forced outages or derates!

• Must use event contribution code 2 to 5 on any additional causes of events during any forced outage or derate.

Primary Event Cause (cont.)Primary Event Cause (cont.)

Time: Work Started/Time: Work Ended (optional)

• Uses 24 hour clock and looks at event start & end dates & times.

Problem Alert (optional)

Man Hours Worked (optional)

Verbal Description (optional)

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

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

Erosion

Corrosion

Electrical

Electronic

Mechanical

Hydraulic

Instruments

Operational

(Same as Amplification Codes)

Typical Contributing FactorsTypical Contributing Factors

Foreign/Wrong Part

Foreign/Incorrect Material

Lubrication Problem

Weld Related

Abnormal Load

Abnormal Temperature

Normal Wear

Particulate Contamination

Abnormal Wear

Set Point Drift

Short/Grounded

Improper Previous Repair

Typical Corrective ActionsTypical Corrective Actions

Recalibrate

Adjust

Temporary Repair

Temporary Bypass

Redesign

Modify

Repair Part(s)

Replace Part(s)

Repair Component(s)

Reseal

Repack

Request License Revision

Method 2

Compare the difference ...Compare the difference ...

Cause Code 1000

U1 Outage

“The unit was brought off line due to water wall leak”

Cause Code 1000

U1 Outage

“Leak. 3 tubes eroded from stuck soot blower. Replaced tubes, soot blower lance.”

Method 1

Additional Cause of EventAdditional Cause of Event

Same layout as primary outage causes

Used to report factors contributing to the cause of event, additional work, factors affecting startup/rampdown

Up to 46 additional repair records allowed

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

For gas turbines and jet engines

• Optional but strongly encouraged

Failure mechanism (columns 50-53)

• Same as Amplification Codes

Trip mechanism (manual or auto) (column 54)

Cumulative fired hours at time of event (columns 55-60)

Cumulative engine starts at time of event (columns 61-65)

Question & Answer

Question:

Riverglenn #1 (a fossil unit) came down for a boiler overhaul on March 3rd. What is the appropriate cause code for this event?

Answer:

1800 - Major Boiler overhaul

• more than 720 hours

1801 - Minor Boiler overhaul

• 720 hours or less

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?

Answer:

Major Turbine overhaul

• Cause Code 4400

• Contribution Code 1

High-Pressure Turbine reblading

• Cause Code 4012

• Contribution Code 1

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?

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.

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?

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

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?

Answer:

The start time of the event is after the end time.

Looking at the description of the event, the better cause code would be 1460, fouling of ID Fan rather than just ID Fan general code 1455.

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”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 StatesUnit States

From the Unit State Chart …From the Unit State Chart …

“Unplanned” – corrective action

From the Unit State Chart …From the Unit State Chart …

“Scheduled” - preventive

Please note …Please note …

Unplanned and scheduled numbers ARE NOT ADDITIVE!!!!

• Maintenance outages in both numbers.

• Use unplanned or scheduled for your uses but don’t compare them.

Two Classes of EquationsTwo Classes of Equations

1. Time-based

• All events

• Without Outside Management Control (OMC)

2. Capacity- or Energy-based

• All events

• Without Outside Management Control (OMC)

Time-based EquationsTime-based Equations

Used by industry and GADS for many years.

All units are equal no matter its MW size because equation is based on time, not the capacity of the unit or units. 500 MW Fossil 50 MW GT

Capacity-based EquationsCapacity-based Equations

Used mostly in-house by industry. Used in one GADS report for many years but not is many.

All units are not equal because equation is based on capacity (not time) of the units.

In this example, the 500MW unit has 10 times the impact on the combination of the 50 & 500 MW units because it is 10 times bigger.

500 MW Fossil

50 MW GT

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?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?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?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 IndicesTime-based Indices

Equivalent Availability Factor (EAF)

Equivalent Unavailability Factor (EUF)

Scheduled Outage Factor (SOF)

Forced Outage Factor (FOF)

Maintenance Outage Factor (MOF)

Planned Outage Factor (POF)

Time-based IndicesTime-based Indices

Energy Factors

• Net Capacity Factor (NCF)

• Net Output Factor (NOF)

• Forced Outage Rate (FOR)

• Equivalent Forced Outage Rate (EFOR)

• Equivalent Forced Outage Rate – Demand (EFORd)

Time-based Equations – Factors

Equivalent Availability Factor (EAF)Equivalent Availability Factor (EAF)

By Definition:

• The fraction of net maximum generation that could be provided after all types of outages and deratings (including seasonal deratings) are taken into account.

• Measures percent of maximum generation available over time.

• Not affected by load following

• The higher the EAF, the better.

• Derates reduce EAF using Equivalent Derated Hours.

What is meant by “Equivalent Derated What is meant by “Equivalent Derated Hours?”Hours?”

This is a method of converting deratings into full outages

The product of the Derated Hours and the size of reduction, divided by NMC

100 MW derate for 4 hours is the same loss as 400 MW outage for 1 hour.

100MWx4hours = 400MWx1hour

1 2 3 4

Equivalent Availability Factor (EAF)Equivalent Availability Factor (EAF)

EAF = (AH - ESDH - EFDH - ESEDH) x 100%PH

Where AH=7760; PH=8760; ESDH=50; EFDH= 500; ESEDH=10; MOH=440

EAF = (8760 – 50 - 500 -10 - 440) x 100% = 88.58%8760

Equivalent Unavailability Factor (EUF)Equivalent Unavailability Factor (EUF)

Compliment of EAF

EUF = 100% - EAF

Percent of time the unit is out of service or restricted from full-load operation due to forced, maintenance & planned outages and deratings.

The lower the EUF the better.

Scheduled Outage Factor (SOF)Scheduled Outage Factor (SOF)

By Definition:

• The percent of time during a specific period that a unit is out of service due to either planned or maintenance outages.

• Outages are scheduled.

PO – “Well in Advance”

MO - Beyond the next weekend.

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

• The lower the SOF, the better.249

Scheduled Outage Factor (SOF)Scheduled Outage Factor (SOF)

SOF = 100% x (POH + MOH)PH

Other Outage FactorsOther Outage Factors

Maintenance Outage Factor (MOF)

Planned Outage Factor (POF)

POF = 100% x (POH)PH

MOF = 100% x (MOH)PH

Forced Outage Factor (FOF)Forced Outage Factor (FOF)

By Definition:

• The percent of time during a specific period that a unit is out of service due to forced outages.

• Outages are not scheduled and occur before the next weekend.

• A measure of the unit’s unavailability due to forced outages over a specific period of time.

• The lower the FOF, the better.

Forced Outage Factor (FOF) Forced Outage Factor (FOF)

FOF = 100% x (FOH) PH

Net Capacity Factor (NCF)Net Capacity Factor (NCF)

By Definition:

• Measures the actual energy generated as a fraction of the maximum possible energy it could have generated at maximum operating capacity.

• Shows how much the unit was used over the period of time.

• The energy produced may be outside the operators control due to dispatch.

• The higher the NCF, the more the unit was used to generate power (moving to “base-load”).

Net Capacity Factor (NCF)Net Capacity Factor (NCF)

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

Net Output Factor (NOF)Net Output Factor (NOF)

By Definition:

• Measures the output of a generating unit as a function of the number of hours it was in service (synchronized to the grid)

• How “hard” was the unit pushed.

• The energy produced may be outside the operators control due to dispatch.

• The higher the NOF, the higher the loading of the unit when on-line.

Net Output Factor (NOF)Net Output Factor (NOF)

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

Comparing NCF and NOFComparing NCF and NOF

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

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

NCF measures % of time at full load.NOF measures the loading of the unit when operated.

Comparing AF/EAF/NCF/NOFComparing AF/EAF/NCF/NOF

NOF > NCF

AF > EAF > NCF

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

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

What can you learn from the What can you learn from the numbers below?numbers below?

EAF NCF NOF

Nuclear 88.35 89.18 98.81

Fossil, coal 84.19 70.96 84.65

Fossil, gas 86.97 13.33 38.38

Fossil, oil 81.86 15.24 49.03

Gas turbines 90.20 2.67 66.70

Hydro 85.98 41.13 70.53

(Data for 2005-2009 GAR Report)260

Meeting Demand in Real TimeMeeting Demand in Real Time

Typical Daily Demand Curve

Base Load

Intermediate Load

Peak Load

Operating Reserves

Energy: Electricity Produced over Time

Capacity: Instantaneous measure of electricity available at peak

(Data for 2005-2009 GAR Report)

EAF NCF NOF Age in '09

Nuclear 88.35 89.18 98.81 29.37

Fossil, coal 84.19 70.96 84.65 42.45

Fossil, gas 86.97 13.33 38.38 45.86

Fossil, oil 81.86 15.24 49.03 44.59

Gas turbines 90.20 2.67 66.70 26.96

Hydro 85.98 41.13 70.53 57.81

Time-based Equations – Rates

Forced Outage RateForced Outage Rate

By Definition:

• The percent of scheduled operating time that a unit is out of service due to unexpected problems or failures.

• Measures the reliability of a unit during scheduled operation

• Sensitive to service time (reserve shutdowns and scheduled outage influence it)

• Best used to compare similar loads:

– base load vs. base load

– cycling vs. cycling

• The lower the FOR, the better. 264

Forced Outage RateForced Outage Rate

Calculation:

FOR = FOH FOH + SH + Syn Hrs + Pmp Hrs

Comparison: unit with high SH vs. low SH(SH = 6000 hrs vs. 600 hrs; FOH = 200 hrs)

FOR = 200 = 3.23% 200 + 6000

FOR = 200 = 25.00% 200 + 600

x 100%

Equivalent Forced Outage RateEquivalent Forced Outage Rate

By Definition:

• The percent of scheduled operating time that a unit is out of service due to unexpected problems or failures AND cannot reach full capability due to forced component or equipment failures

• The probability that a unit will not meet its demanded generation requirements.

• Good measure of reliability

• The lower the EFOR, the better.

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%

Equivalent Forced Outage Rate – Equivalent Forced Outage Rate – Demand (EFORd)Demand (EFORd)

Markov equation developed in 1970’s

Used by the industry for many years

• PJM Interconnection (20 years)

• Similar to that used by the Canadian Electricity Association (20 years)

• Being use by the CEA, PJM, New York ISO, ISO New England, and California ISO.

Interpretation:

• The probability that a unit will not meet its demand periods for generating requirements.

• Best measure of reliability for all loading types (base, cycling, peaking, etc.)

• Best measure of reliability for all unit types (fossil, nuclear, gas turbines, diesels, etc.)

• For demand period measures and not for the full 24-hour clock.

• The lower the EFORd, the better.270

EFORd Equation:EFORd Equation:

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

Where: FOHd = f x FOH f = [(1/r)+(1/T)]

[(1/r)+(1/T)+(1/D)]

r= FOH/(# of FOH occur.) T= RSH/(# of attempted Starts) D= SH/(# of actual starts) EFDHd = fp x EFDH

fp = SH/AH272

Example of EFORd vs. EFORExample of EFORd vs. EFOR

EFOR vs. EFORdGeneral Trend

Increasing RSH / Decreasing SH (All other numbers in calculation are contant.)

EFOR, range from 6.2 to 130.0%

EFORd, range from 4.7 to 30.7%

Example of EFORd vs. EFORExample of EFORd vs. EFOR

EFOR vs. EFORdGas Turbines 2004-2008

Corresponding EFOR & EFORd Values

EFORd EFOR 274

Limiting Conditions for EFORdLimiting Conditions for EFORd

Case SH FOH RSH FORd EFORd

Base >0 >0 >0 Applicable Applicable

1 0 >0 >0Cannot be determined

Cannot be determined

2 0 0 >0Cannot be determined

3 0 >0 0Cannot be determined

4 >0 0 >0 0 EFDH/AH

5 >0 0 0 0 EFDH/SH

6 >0 >0 0 FOR EFOR

7 0 0 0Cannot be determined

Base case is normal. Cases 4, 5, 6: Computed FORd, EFORd are valid. 275

(Data for 2005-2009 GAR Report)

FOR EFOR EFORd SH RSH

Nuclear 2.16 3.09 3.09 7,864.04 6.03

Fossil, coal 5.37 7.46 7.08 6,988.47 615.3

Fossil, gas 10.37 11.66 7.24 2,506.42 4,891.71

Fossil, oil 15.33 16.42 11.58 2,682.17 4,465.38

Gas turbines 53.73 54.10 8.86 241.14 7,823.34

Hydro 5.71 5.93 5.16 4,972.45 1,907.60

How to Avoid Misleading EFORdHow to Avoid Misleading EFORd

Use a large population of units.

Use a long period of time if analyzing a single unit (at least one year.) Monthly FORd or EFORd may work on some months but not all.

Check data! If Service Hours is zero, increase population or period so it is not zero.

EAF + EFOR = 100%?EAF + EFOR = 100%?

Given: PH = 8760, SH = 10, RSH = 8460. FOH = 290. No deratings

EAF = AF = AH PH

EAF = 8470 8760

EAF = 97.7%

EFOR = FOR = FOH__ (SH+ FOH)

EFOR = 290____ (290 + 10)

EFOR = 97.7%

Factors and rates Factors and rates are notare not additive additive and not complementary!and not complementary!

Other Equations in IEEE 762Other Equations in IEEE 762

Forced Outage Rate Demand- FORd

FORd = FOHd x 100% [FOHd + SH]

whereFOHd = f x FOH

r=Average Forced outage duration = (FOH) / (# of FO occurrences)D=Average demand time = (SH) / (# of unit actual starts)T=Average reserve shutdown time = (RSH) / (# of unit attempted starts)

DTrTr111

Equivalent Maintenance Outage Factor

Equivalent Planned Outage Factor

Equivalent Forced Outage Factor

EMOF = 100% x (MOH + EMDH)PH

EPOF = 100% x (POH + EPDH)PH

EFOF = 100% x (FOH + EFDH)PH 280

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.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, XEAFComparing EAF, WEAF, XEAF

Time-based is simple to understand and calculate. Good method for units of the same MW size.

Capacity-based is more complicated to calculate but provides a more accurate view of total system capabilities, especially for units of different MW sizes

OMC-based allows power stations a fair grade on performance by removing outside influences on production.

Commercial Availability

Commercial AvailabilityCommercial Availability

First developed in the United Kingdom but now used in a number of countries that deregulate the power industry.

No equation.

Marketing procedure for increasing the profits while minimizing expenditures. The concept is to have the unit available for generation during high income periods and repair the unit on low income periods.

Commercial AvailabilityCommercial Availability

Unit Available

Needed for Generation

Unit Available

Not needed for Generation

Unit not available

Not Needed for Generation

Unit not available

Needed for Generation

Make Big Revenue, +$

Lost opportunity, -$Good time for repairs

Not competitive, -$

Words About Distributions

Beware of Statistical ScatterBeware of Statistical Scatter

Averages or means can be misleading

• Sample should be at least 30

Also use median, mode, standard deviation, range

Beware of bimodal distributions

• Separate unique populations

• pc-GAR, SAS, scatter diagrams, etc.

Weighted Equivalent Availability Factor Weighted Equivalent Availability Factor

Fossil-Steam Units in USA for Year 2004-2008 Only

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 Equivalent Availability Factor Weighted Equivalent Availability Factor

Fossil-steam units in USA; 2004-2008

Fossil Unit WEAF by Size

100-199MW

200-299MW

300-399MW

400-499MW

500-599MW

600-699MW

700-799MW

800-899MW

WEAF and Age of Fossil UnitsWEAF and Age of Fossil UnitsAll Sizes and FuelsAll Sizes and Fuels

Fossil-steam units in USA 1982-2008

Fossil Unit Weighted Equiv. Availabliity Factor (WEAF) and Unit Age

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.

Words About Pooling DataWords About Pooling Data

Example of the proper pooling for FOR for 5 units:

FOH = 840 + 78 + 67 + 117 + 546 = 1648 / 5 = 329.60

SH = 6760 + 7610 + 116 + 765 + 7760 = 23011 / 5 = 4602.20

Average FOR = [FOH/(FOH + SH)] X 100% = 100% x [329.60/(4602.20+ 329.60)] = 6.62%

*****************************************************

Example of the WRONG pooling of AF for 5 units:

Average FOR = (11.05% + 1.01% + 36.61% + 13.27% + 6.57%) = 68.51% / 5 = 13.70%

GADS Standard for EFORdGADS Standard for EFORd

Will follow IEEE recommendation as shown in Appendix F, Notes 1 and 2.

Will use Method 2 for calculating EFORd and FORd in all GADS publications and pc-GAR.

• Consistency – all other GADS equations sum hours in both the denominator and numerator before division.

• Allow calculations of smaller groups. By allowing sums, smaller groups of units can be used to calculate EFORd without experiencing the divide by zero problem (see Note #2 for Appendix F).

Pooling Time-based StatisticsPooling Time-based Statistics

Equivalent Maintenance Outage Factor

Equivalent Planned Outage Factor

Equivalent Forced Outage Factor

EMOF = 100% x Σ (MOH + EMDH)Σ PH

EPOF = 100% x Σ (POH + EPDH)Σ PH

EFOF = 100% x Σ (FOH + EFDH)Σ PH

Pooling Weighted StatisticsPooling Weighted Statistics

Weighted Equivalent Maintenance Outage Factor

Weighted Equivalent Planned Outage Factor

Weighted Equivalent Forced Outage Factor

WEMOF = 100% x Σ [(MOH + EMDH) x NMC]Σ (PH x NMC)

WEPOF = 100% x Σ [(POH + EPDH) x NMC]Σ (PH x NMC)

WEFOF = 100% x Σ (FOH + EFDH) x NMC]Σ (PH x NMC)

What’s new with GADS?

GADS and the World Energy CouncilGADS and the World Energy Council

GADS is involved with the World Energy Council (WEC) and its Performance of Generating Plant (PGP) subcommittee.

• Teaching workshops

• Providing software

• Wanting to create a WEC-GADS database and a “WEC pc-GAR”

Continue to explore best way to collect unit specific data on fossil units worldwide for WEC pc-GAR software.

Continuing ProjectsContinuing Projects

Adding wind generators to GADS

• Working group formed to determine design, event, cause codes, etc. for data collection.

• Discussion of wind data collection is on Thursday at 8:00 a.m.

Continuing ProjectsContinuing 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 CEAExchange data with Europe and CEA

Exchange data with Europe and the Canadian Electricity Association (CEA)

Continue correspondence with the International Atomic Power Agency (IAEA)

Design Data Time Stamping

Design Data Time StampingDesign Data Time Stamping

Tracking changes in plants with time.

Addition/removal of equipment like bag houses, mechanical scrubbers, etc.

Upgrading or changing equipment like pumps, fans, etc.

Will be sent out to each reporter by the end of November this year (if not sooner).

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: joanne.rura@nerc.net

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-GARAccess to pc-GAR

If you are a generating company in North America and report your GADS data to NERC, you can purchase pc-GAR.

If you are a generating company in North America and do not report your GADS data to NERC, you cannot purchase pc-GAR.

If you are a generating company outside North America and either do or do not report GADS data to GADS, you can purchase pc-GAR.

Question & Answer

Contact:

Mike CurleyManager of GADS Servicesmike.curley@nerc.net801.756.0972

NERC GADS 101 Data Reporting Workshop

nerc gads

gads databasesdesignwhat

nerc backgroundnerc

generation facilities

reliability legislation

bulkpower system

bulk power

electric industry

Documents

Tālākās attīstības vajadzības - Engures...

NERC GADS Wind Data Reporting Workshop

Cuadernillo Completo GADS

NERC GADS Benchmarking Workshop 2011 (1)

Appendix B06: Index To Combined Cycle Unit Cause...

PAŠNOVĒRTĒJUMA ZIŅOJUMS · 2016.gads 6 Skolēnu...

The Anatomy of a Wind Plant - NERC Training/Wind...

Appendix B05: Index To Co-Generator Block Unit...

A QUANTITATIVE STUDY OF WIND TURBINE … · IEC 61400-25...

G. Michael Curley Manager of GADS Services October 27-29,...

ATTĪSTĪBAS PLĀNS€¦ · Gads 2011. gads (LVL) 2012....

International Financial Reporting Standards (IFRS) Sept 2010...

DRAFT Cyber Security Incident Reporting and …...

1991. gads

Appendix F: Performance Indexes and Equations · Appendix.....

SEB zaļais gads