gads_101_data_reporting_workshop_october_2017 … cycle blocks and their related components (gas...

GADS Data Reporting Workshop

2017 GADS Data Reporting WorkshopsMay, August & October, 2017

Introduction and Overview

2017 GADS Data Reporting Workshops – Module 01October, 2017

3 RELIABILITY | ACCOUNTABILITY

Primary Instructors

• Introduction of Facilitators Leeth DePriest – Southern Company Services and Chairman GADS Working Group

Mike Curley – Navigant Consulting (MicroGADS Product Manager), GADSWG Observer and former NERC GADS Services Manager

• Introduction of Attendees Your name Company GADS experience


Welcome

• NERC Performance Analysis Staff Donna Pratt – Performance Analysis Manager, Data Analytics Margaret Pate – Liaison, Reliability Risk Analysis and Control Lee Thaubald ‐ Technical Analyst David Till – Senior Manager


Agenda

• What is NERC? • What is GADS? Why mandatory GADS? What units are required?

• Data Input Needed• 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.


Questions?

History of NERC and GADS



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


What is GADS?

A - Availability

S - System

G - Generating

D - Data


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.


Unit Availability Database

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

• Not interested in dispatch requirements or needs by the system!

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


GADS became mandatory in 2012


Mandatory GADS – 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 started January 1, 2012 and 20 MW and larger started 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.


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.


Recommendations – In-house Audits

• In‐house review of GADS data by the reporting generating company has always been strongly encouraged.

• Each reporting generating company shall continue to be responsible for collecting, monitoring, updating and correcting their own GADS design, event, and performance data.


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


Questions?

Design Data & Fundamentals



The GADS Data Monster


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.

• 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.


Unit Types (Appendix C)

Unit Type Coding SeriesFossil (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


Recommendations - Design

• 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.


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).


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

Treat as Normal Unit.

If sum over 20 MW, then reportable to GADS –Treat as “Miscellaneous Unit”


Design Updating?

• Is additional design needed to analyze the GADS data? Gas turbine manufacturer? Steam turbine details? Boiler design (subcritical vs. supercritical)? Time stamping?


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.


Questions?

Outage Event Reporting



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.


Event Identification

• Utility (Company) Code – a three character alpha‐numeric code that identifies the reporting organization. Assigned by OATI for NERC (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)

• The combination of the utility and unit codes uniquely identifies your units!


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.

Reliability compliance reports are still enforced!!



• 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. Additional descriptions on MB are being considered by the GADSWG.



• 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.


Note Regarding NERC Compliance

• When a unit goes into IR or MB, that unit will not be considered in fleet unit reporting statistics like EAF, EFORd, etc.

• HOWEVER, the unit‐level compliance MAY still be open for NERC auditing under the NERC Reliability Standards [Critical Infrastructure Protection (CIP); Emergency Preparedness and Operations (EOP); Protection and Control (PRC); etc.].

• WECC requires you continue to comply with the standards. Check with your Region for rules.


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!


Outage Types

• Timing starts WHEN YOU DETECT THE PROBLEM!– Forced Outages (four types)– Maintenance Outage (one type plus extension)– Planned outage (one type plus extension)

Forced Outage Maintenance Outage Planned Outage

Can’t start (SF)

Now or very soon (U1)

6 hours (U2)

After the end of next weekend (MO/ME)

Planned “Well In Advance” (PO/PE)

Before the End of next Weekend (U3)


From the Unit States Diagram

“Unplanned”

Forced + Maintenance + Planned


From the Unit States Diagram

Forced + Maintenance + Planned

“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.


From GADS DRI

• PO – Planned Outage

An outage that is scheduled well in advance and is of a predetermined duration, can last for several weeks, and occurs only once or twice a year. Turbine and boiler overhauls or inspections, testing, and nuclear refueling are typical planned outages. For a planned outage, all of the specific individual maintenance and operational tasks to be performed are determined in advance and are referred to as the "original scope of work." The general task of repairing turbines, boilers, pumps, etc. is not considered a work scope because it does not define the individual tasks to be performed. For example, if a general task such as repair boiler is considered the work scope, it is impossible to conclude that any boiler work falls outside of the original scope of work. Discovery work and re‐work which render the unit out of service beyond the estimated PO end date are not considered part of the original scope of work. A planned extension may be used only in instances where the original scope of work requires more time to complete than the estimated time. For example, if an inspection that is in the original scope of work for the planned outage takes longer than scheduled, the extra time should be coded as an extension (PE). However, if damage found during the inspection results in an extension of the outage, the extra time required to make repairs should be coded as a forced outage.

• MO –Maintenance Outage

An outage that can be deferred beyond the end of the next weekend (defined as Sunday at 2400 hours or as Sunday turns into Monday), but requires that the unit be removed from service, another outage state, or Reserve Shutdown state before the next Planned Outage (PO). Characteristically, a MO can occur any time during the year, has a flexible start date, may or may not have a predetermined duration, and is usually much shorter than a PO. Discovery work and re‐work which render the unit out of service beyond the estimated MO end date are not considered part of the original scope of work. A maintenance extension may be used only in instances where the original scope of work requires more time to complete than the estimated time. For example, if an inspection that is in the original scope of work for the outage takes longer than scheduled, the extra time should be coded as an extension (ME). If the damage found during the inspection is of a nature that the unit could be put back on‐line and be operational past the end of the upcoming weekend, the work could be considered MO or ME. If the inspection reveals damage that prevents the unit from operating past the upcoming weekend, the extended work time should be Forced Outage (U1, U2, or U3).

Note: If an outage occurs before Friday at 2400 hours (or before Friday turns into Saturday), the above definition applies. But if the outage occurs after Friday at 2400 hours and before Sunday at 2400 hours (the 48 hours of Saturday and Sunday), the MO will only apply if the outage can be delayed past the next, not current, weekend. If the outage cannot be deferred, the outage shall be a forced event.


From GADS DRI

• PE and ME Rules and Regulations

The “predetermined duration” of an outage also determines the “estimated completion date” of the PO or MO. If the unit is scheduled for four weeks of repairs, then the unit is expected back in service at a certain date four weeks after the start of the outage. In cases where the outage is moved up or back according to the needs of the operating company, ISO, or power pool, then the start of the outage plus duration of the outage determines the new completion date. As long as the outage is no longer than planned, the expected completion date is moved to coincide with the predetermined duration period.

If the unit is on outage (for example, U1 outage due to a boiler tube leak) at the time the unit is scheduled to start the PO or MO work, then the work on the cause of the outage (tube repairs) must be completed before changing from the U1 outage to the PO or MO outage. PO and MO work can start but is not counted as PO or MO work until the U1 repairs are complete.

All work during PO and MO events is determined in advance and is referred to as the “original scope of work.” Use ME and PE only in instances where the original scope of work requires more time to complete than originally scheduled. Where applicable, the extension of the planned or maintenance outage may be required to be approved in advance by your power pool or ISO. Advance warning of an extension is very important. However, GADS is not a dispatch‐orientated database but rather an equipment‐orientated one. The reporting of the PE and ME is based on IEEE 762‐GADS rules, not ISO requirements. Therefore, if the extension meets the GADS rules, then report it as an ME or PE and not a U1 when reporting to GADS only.

Do not use ME and PE in instances where unexpected problems or conditions are discovered during the outage which render the unitout of service beyond the estimated end date of the PO or MO. Report these delays as Unplanned (Forced) Outage‐Immediate (U1). Do not use ME and PE if unexpected problems occur during unit startup. If a unit completes a PO or MO before the original estimatedcompletion date and volunteers to return to service (i.e., the unit is released to dispatch), then any problems causing outages or deratings after that date are not considered to be part of the PO or MO.


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 Outages (FO)

• U1 – Unplanned (Forced) Outage — Immediate– An outage that requires immediate removal of a unit from

service, another Outage State, or a Reserve Shutdown state

– Requires cause code amplification code ONLY IF the U1 is preceded by the unit being in service (generating power)! T1 - Tripped/shutdown grid separation – automatic T2 - Tripped/shutdown grid separation – manual 84 - Unknown – investigation underway

Required As Shown Above



• U1 – Unplanned (Forced) Outage — Immediate– If the U1 is not a trip but the result of a change of state

(from planned outage to U1, for example), then the amplification code can be any appropriate amplification code if the reporter chooses to report amplification codes.

In-service (generating power) U1 Outage

PO, MO, U1, etc. U1 Outage

Amp code required = T1 (automatic) or T2 (manual)

No amp code required



• Forced‐type Outages 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.

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 42,762 FO events in 2016, 84.5% are U1 outages (36,130 events)

9.4 % are SF outages (4,032 events)

4.0 % are U2 outages (1,706 events)

2.1 % is U3 outages (894 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

0

100

200

300

400

500

600

700

0 1 2 3 4 5 6Jan 3 @ 0430 Jan 8 @ 1700

Forced OutageCC 4240

Capacity (MW)


Questions?

Examples of Outage Reporting



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: Not 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.



• A duel fuel combustion turbine was scheduled for an eight day planned outage. The critical path was work on the fuel oil system flow divider. The plant also did some exciter work to attempt to restore the unit MVAR output. After eight days, the work was completed and the unit was placed on line to test, check‐out, verify that all the repairs were successful. The unit was on line for about an hour when the exciter grounded and tripped the unit. The exciter was sent off to be rewound as a result of this event. The unit remained off for 14‐15 additional days.

• Is the work to rewind the exciter forced or PO?




• Forced outage. Why?




• Forced outage. Why? This is not part of the original scope and is a new failure.



• A fossil steam unit had a high efficiency HP turbine installed several years ago. The turbine did not pass the guarantee performance test. The vender agreed to make changes to the steam path so that the turbine would perform as designed. The repairs were scheduled to coincide with a routine planned outage. The turbine inner cylinder was removed and sent to the vender for the steam path repairs. The vender found extensive cracks in the inner cylinder that had to be repaired before the steam path work could be completed. This caused the outage to run approximately 3 weeks past the scheduled end date. From what we know, the crack repair was totally unexpected.

• Would you call this an extension or a forced outage?




• Forced Outage. Why?




• Forced Outage. Why? The repair was unexpected and not part of the work scope. It is important to know the work scope details.


Scenario #10 – Report Testing

• Riverglenn #1 completed its steam turbine overhaul when the breaker malfunctioned causing an SF event. Following the breaker repair, the unit tested the steam turbine balance, stop valves and new instrumentation installed during the overhaul as scheduled.

• What event type should be used to report the testing?

PO -Overhaul SF Event Testing





• PO (and PD if needed). Why?






• Even though there was a SF event in the middle, the testing is still part of the original PO event work.



Scenario #11 – Series of Outages

• Riverglenn #1 was scheduled for a PO on Jan. 8th but was removed from service on Jan. 2nd due to boiler tube leak. On Jan. 8th the unit transitioned into the PO. During the PO, it was discovered that gas exit duct had issues (not part of the OSW) which caused extension of the original PO time by 4 days. The unit was scheduled for a Turbine Over‐speed Trip testing after the unit was returned to service. Tests were completed and Riverglenn returned to service with several boiler water chemistry holds until boiler water chemistry was good for full rated boiler pressure.



Tube

Lea

k

Plan

ned

Out

age

Exit

Gas

D

uct W

ork

Ove

r-sp

eed

Test

ing

Silic

a H

olds

What are the types of outages/derating for each event?



Tube

Lea

k

Plan

ned

Out

age

Exit

Gas

D

uct W

ork

Ove

r-sp

eed

Test

ing

Silic

a H

olds

What are the types of outages/derating for each event?

U1,

U2,

U3,

MO

PO U1

PD

Is th

is a

der

ate?


More Examples?

Appendix G – Examples and Recommended Methods


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.


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!


Questions?

Derating Event Reporting



Unit States (Deratings)

• What is a derate? A derate exists when a unit cannot generate at 100% capacity

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

A derate ends when the equipment is either ready for orput 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.


Derating Types

• Timing starts WHEN YOU DETECT THE PROBLEM!– Forced Deratings (three types)– Maintenance Deratings (one type plus extension)– Planned Deratings (one type plus extension)

Forced Derate Maintenance Derate Planned Derate

Now or very soon (D1)

6 hours (D2)

After the end of next weekend (D4/DM)

Planned “Well In Advance” (PD/DP)

Before the End of next Weekend (D3)


Unit States (Deratings)

• Report a derate or not? If the derate is less than 2% NMC AND lasts 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 2016, there were 95,887 forced derating events 94.2% are D1 derates (90,273 events) 4.4% are D2 derates (4,228 events) 1.4% are D3 derates (1,386 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.



• GADSWG example of multiple derating extensions for different causes



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 CapacityBasic Planned Derating

PlannedDeratingExtended 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

0

100

200

300

400

500

600

700

0 1 2 3 4 5 6

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 deratings 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

0

100

200

300

400

500

600

700

0 1 2 3 4 5 6

3/9@:0845 3/9@1800

Capacity (MW)

Forced Derating CC 0253

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

0

100

200

300

400

500

600

700

0 1 2 3 4 5 6

7/3@1430 7/23@1145

Capacity (MW)D4 CC 3112

D1 CC 3410

7/19@1115 7/19@1200


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 Deratings

Event 1

Event 2



Single Dominant Derating

DominantDerating –Event 3



Overlapping Dominant Deratings



Dominant Derating 3 SHADOWS portion of Event 4



Overlapping 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.


Questions?

Other Event Type Reporting



Other Unit States

• Reserve Shutdown – unit not synchronized but readyfor 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?


Questions?

Capacity/Event times Reporting



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 CapacityBasic Planned Derating

PlannedDeratingExtended 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


Missing Capacity Calculation!

• Factors are based on data reported to GADS in 1998 as follows: Fossil units –> 0.05 Nuclear units –> 0.05 Gas turbines/jets –> 0.02 Diesel units –> 0.00 Hydro/pumped storage units –> 0.02 Miscellaneous units –> 0.04

• Unless …



• 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.


Questions?

Descripting “What Happened?”



It Takes Team Work to Discovery the Causes of Outages!


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

167 RELIABILITY | ACCOUNTABILITYRELIABILITY | ACCOUNTABILITY

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


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” Does anyone agree with this?


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 IFthey 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 hours1801 ‐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 bladesIs 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.


Questions?

Performance Data Reporting



Performance Reporting (Section IV)


Why Collect Performance Records?

• Performance data provides information, in a summarized format, pertaining to overall unit operation during a particular month in a given year.

• This data is needed to calculate unit performance, reliability, and availability statistics. – Starting Reliability– Equivalent Forced Outage Rate – Demand (EFORd)

• Performance data is required for all unit types and sizes reported to the GADS program.


Why Collect Performance Records?

• Double check against event records– Event and performance hours must match down to

0.03 hrs.• Monthly fuels• Monthly generation

– Annual, monthly, seasonal, or rolling reports


Performance Report

• Only the “05” format is accepted by WebE-GADS.– To check if your program is using the correct format

• Open the performance file (in text format) with Notepad.

• If the first two digits of the file are “05”, then you are okay.

• If the first two digits of the file are “95”, then update your software.

• All performance text files must have the extension “txt” or it will not upload to WebE-GADS.

• Data is due 45 days after the end of each quarter year.• Monthly or year-to-date data is accepted by WebE-GADS.

– Strongly recommend year-to-date submittals!


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 Performance

• The data provided in this section are used to calculate performance statistics.

• Both gross and net values are requested. Net values are preferred but reporting gross data only is acceptable. Reporting (either) gross and (or) net data depends on how the unit is electrically metered.

• If you meter on a single basis, but can estimate the other, do so and enter the estimated value in the appropriate field.


Gross Vs. Net Capacities

GeneratorGross

Generation Meter

Net Generation

Meter

GMC, GDCGross Generation

NMC, NDCNet Generation

Internal plant or auxiliary use

Electric Production

Power out toThe customer


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

You are encouraged to report Gross numbers!!


Dependable Capacities

• GDC is the gross power level that the unit can sustain during a given period if there are no equipment, operating, or regulatory restrictions.

• By definition, therefore, the GDC is the GMC modified for ambient limitations.

• “Ambient limits” refer to outside, weather‐related losses, to the unit and not related to equipment. For example, your ID Fans are designed to pull air with a maximum temperature of 100⁰ F and it is 110⁰ F.

GMC – (Ambient Losses) = GDC


Gross Actual Generation (GAG)

• The actual number of gross electrical mega‐watt‐hours (MWh) generated by the unit during the month.

• If you report both Service Hours and Gross Actual Generation (one to 99999.99), then GMC or GDC must also be reported.

• If both service hours and a gross capacity value are reported, Gross Actual Generation must also be reported.

• GAG will always be zero or positive!


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!


Dependable Capacities

• NDC is the net power level that the unit can sustain during a given period if there are no equipment, operating, or regulatory restrictions.

• By definition, therefore, the NDC is the NMC modified for ambient limitations.

• “Ambient limits” refer to outside, weather‐related losses, to the unit and not related to equipment. For example, your ID Fans are designed to pull air with a maximum temperature of 100⁰ F and it is 110⁰ F.

NMC – (Ambient Losses) = NDC


Net Actual Generation (NAG)

• The actual number of net electrical mega‐watt‐hours (MWh) generated by the unit during the month.

• If you report both Service Hours and Net Actual Generation (one to 99999.99), then NMC or NDC must also be reported.

• If both service hours and a net capacity value are reported, Net Actual Generation must also be reported.

• Negative NAG can be reported and will be accepted.


Gas Turbine/Jet Capacities

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

• International Organization of Standardization (ISO) standard for the unit at Standard Temperatures and Pressures (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



• 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)



• If you only report either the gross or the net capacities, then the GADS editing program or WebE-GADS will calculate any missing GMC, GDC, NMC, or NDC 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

Note: these percentages may change in the future!



• 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• Unit loading is how the unit was operated or loaded during the

month being reported.• If the unit was off‐line during the entire period, describe how

the unit typically would have been loaded had it been on‐line.

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 using the formula:

Actual Unit Starts + Start-Up Failures = Attempted Unit Starts

• 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 (Driving your car to work.)

• Reserve Shutdown Hours (RSH) (required) Available for load but not used (economic) (Your car in the garage or a parking lot while you are shopping.)


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 Its field is controlled by a voltage regulator to either generate or absorb reactive power as needed to adjust the grid's voltage, or to improve power factor.

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



• 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 Original Scope of Work (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 twoexceptions 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. – Start reporting a new unit or transfer of a unit from one owner to the next at the beginning of the month.

• 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.– Report the retired unit until the end of the month.


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: NUAny 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)


Questions?

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.


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.


Questions?

OATI Training



OATI

• Brian Nolan Senior Project Manager Over 25 years industry experience 22 years with NERC 5 years with OATI Contact Brian at:

o Phone: 763.201.2000o [email protected]

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