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EEA Workshop
April 22, 2014
Workshop Process
Dan Woodfin
2
Workshop Process
• Workshop 1
– Background on EEA
– Identify Issues
• Workshop 2
– Options to Resolve Issues
– Consensus Items
– Future Activities
3
Background on EEA
Stephen Solis
4
NERC Standards
• Energy Emergency Alerts were first part of
the NERC Operating Policies (Policy 5.C.)
• NERC Operating Policy 5.C. was transferred
to EOP-002 as part of version 0 standards
related to FERC Order 693 in 2007.
• Appendix 5C (Energy Emergency Alerts) of
the NERC Operating Policy was also moved
over as Attachment 1-EOP-002 as part of
EOP-002.
5
NERC Standards
• Primary Applicable Standard in effect is EOP002-3.1 Capacity and Energy Emergencies.
• EOP-001-2.1b is applicable to ensure
appropriate plans are in place.
• EOP-003-2 is applicable related to load shed
plans and actions for EEA3.
• EOP-004-2 is applicable related to required
reporting.
6
Single vs Multiple BA Interconnection
• EEA requirements are built around the
concept of minimizing risk associated with
a BA area “leaning” on another area in a
multiple BA Interconnection.
• CPS and DCS criteria are measures that
are expected to be met even during
emergencies to minimize the risk on the
Interconnection.
7
Multiple BA Interconnection
Neighbor D
Neighbor C
Energy
Deficient
Entity (LSE
or BA)
Neighbor A
• Area Control Error (ACE) has
an Interchange component
• Frequency is supported by
remainder of Interconnection
• Emergency status allows
additional transmission
capacity by modifying
transmission service priority
• Importance of reducing risk
associated with “leaning” on
other areas highlighted by
requirement to shed load if
CPS and DCS cannot be met.
Neighbor B
8
Single BA Interconnection
DC
Tie
Single
BA
DC
Tie
• ACE does not have an interchange
component, only frequency.
• Frequency is only supported by the
single BA area.
• Transmission capacity is not
reserved (ERCOT)
• No “leaning” risk, frequency
preservation is priority.
• Frequency Responsive Reserves
are more critical without additional
BA’s support for disturbance.
9
Single vs Multiple BA Interconnection
• ERCOT is a single BA Interconnection.
• Frequency preservation and frequency
responsive reserves are focus during an
EEA in a single BA area.
10
Questions
11
Physical Responsive Capability
(PRC) Calculation
Bill Blevins
12
Physical Responsive Capability (PRC)
A representation of the total amount of system wide On-Line
capability that has a high probability of being able to quickly
respond to system disturbances.
1.
2.
3.
4.
Control room operators monitor PRC for determining OCN,
Advisory, Watch and EEA
Currently PRC includes available capability from Online
Generation, Loads Resources and Hydro units on Synchronous
Condenser mode
PRC uses a Reserve Discount Factor (RDF) to account for effect
of temperature on Generator Capability
Conventional Generation Resources and Controllable Load
Resources maximum contribution to PRC is limited to 20% of their
HSL*RDF

5.
6.
Why 20%? The Generator with a governor droop setting of 5% will provide
20% of its HSL as Governor Response if Frequency drops to 59.40 Hz from
60.00 Hz.
Hydro Resources operating under synchronous condenser fast
response mode can contribute their full HSL*RDF towards PRC
Non-Controllable Load Resources providing RRS is 100%
counted towards PRC.
13
Physical Responsive Capability (PRC)
The ERCOT-wide Physical Responsive Capability (PRC) calculated as follows:
14
Physical Responsive Capability (PRC)
15
Changes to PRC in near Future
1. Once NPRR-573 is implemented, Wind Generation
Resources that are Primary Frequency Response
capable will be contributing to the PRC. Maximum
contribution from WGRs will also be limited to 20% of
their HSL.
2. Once NPRR-555 is implemented Controllable Load
Resource (CLR) that are active in SCED will also be
contributing to PRC. Maximum contribution from CLR will
also be limited to 20% of their net telemetered
consumption.
3. Once recently approved NPRR-598 is implemented,
Generation Resources telemetering ONTEST, STARTUP
or SHUTDOWN Resources Status will be excluded from
PRC calculation.
16
Questions?
Current Procedures and Triggers
Colleen Frosch
18
Preliminary Actions
19
EEA Steps
EEA procedure in the ERCOT Protocols defined by levels
1
Maintain 2,300 MW of on-line reserves
2
Maintain 1,750 MW of on-line reserves. Interrupt loads providing
Responsive Reserve Service. Interrupt loads providing Emergency
Response Service (ERS).
3
Maintain System frequency at or above 59.8 Hz and instruct TSPs
and DSPs to shed firm load in rotating blocks.
20
EEA Level 1 – Maintain a total of 2,300 MW of PRC
ERCOT shall:
• Notify the Southwest Power Pool Reliability Coordinator;
• Request available Generation Resources that can perform within the
expected timeframe of the emergency to come On-Line by initiating
manual HRUC or through Dispatch Instruction;
• Use available DC Tie import capacity not already being used;
• Issue a Dispatch Instruction for Resources to remain On-Line which,
before start of emergency, were scheduled to come Off- Line; and
• At ERCOT’s discretion, deploy available contracted ERS-30. June –
September weather-sensitive ERS is available.
21
EEA Level 1 – Maintain a total of 2,300 MW of PRC
QSEs shall:
• Ensure COPs and telemetered HSLs are updated and reflect all
Resource delays and limitations; and
• Suspend any ongoing ERCOT required Resource performing testing.
22
EEA Level 1 – Maintain a total of 2,300 MW of PRC
• TO Load Management Program
– Deploy all available capacity from their Load Management Programs
– Only applies June through September
– Currently 5 TOs participate
23
EEA Level 2 – Maintain 60 Hz or 1,750 of PRC
In addition to the measures associated with EEA Level 1, ERCOT shall
take the following steps:
• Instruct TSPs and DSPs or their agents to:
– reduce Customers’ Load by using distribution voltage reduction
measures, if deemed beneficial by the TSP, DSP, or their agents.
• Instruct QSEs to deploy:
– available contracted ERS-10 Resources
– RRS supplied from Load Resources (controlled by high-set
under-frequency relays).
ERCOT may deploy ERS-10, ERS-30, or RRS simultaneously or
separately, and in any order. June – September Weather-Sensitive
ERS is available.
24
EEA Level 3 – Maintain 59.8 Hz or greater
•
In addition to measures associated with EEA Levels 1 and 2, ERCOT will
direct all TSPs and DSPs or their agents to shed firm Load, in 100 MW
blocks, as documented in the Operating Guides in order to maintain a
steady state system frequency of 59.8 Hz.
•
In addition to measures associated with EEA Levels 1 and 2, TSPs and
DSPs or their agents will keep in mind the need to protect the safety and
health of the community and the essential human needs of the citizens.
Whenever possible, TSPs and DSPs or their agents shall not manually drop
Load connected to under-frequency relays during the implementation of the
EEA.
25
Questions?
History of EEA
Bill Blevins
27
Objectives
• Summarize EEA historical information
• Discuss recent weather challenges
• Identify variables leading to EEAs
28
History of Energy Emergencies
EECP/EEA history
10
9
8
7
6
Total
5
4
3
2
1
0
EECP1
EECP2
EECP3
EECP4
EEA1
EEA2
EEA2A
EEA2B
EEA3
97
2
98
7
99
4
00
01
02
03
1
04
05
06
3
07
10
08
1
1
09
10
11
3
6
12
13
14
1
1
1
1
1
1
29
Note EECP was converted to EEA in after 2008
2008-2014 Categories of EEA events
6%
6%
Sudden Unit Trip
41%
Large Cap Unavail due to Forced Outage
and Derate
High Summer Demand
Wind Forecast/Ramp
35%
Unseasonable Weather during Maint
season
12%
30
Sudden Unit Trip
•
•
•
•
Example
2010
2011
2014
31
EEA-1 May 15th 2010
Executive Summary
At 16:13:49 on May 15th, 2010, Unit A tripped causing the loss of 815 MW. One minute and 18 seconds
later, Unit B tripped causing the loss of 745 MW of generation, for a total of 1560 MW.
ERCOT ISO frequency initially dropped to 59.71 Hz immediately after the Unit A trip at 16:13:49. System
Frequency recovered to 59.76 Hz before Unit B tripped at 16:15:07. As a result of the trip of Unit B the
frequency dropped to 59.69 Hz. This dip below 59.7 Hz caused a total of 1111.8 MW of Responsive
Reserve, in the form of Load acting as Resource (LaaR), to be automatically deployed.
In addition to the LaaRs, 1152 MW of Generation Responsive Reserve was deployed from the 3484 MW of
Adjusted Responsive Reserve available at the beginning of the event.
ERCOT ISO Operators recognized that this was not a NERC Disturbance Control Standard (DCS) event
as the two trips occurred more than 1 minute apart and were considered separate contingencies.
At 16:30 ERCOT implemented Level 1 of its Energy Emergency Alert (EEA). EEA Level 1 was declared
due to the ERCOT Adjusted Responsive Reserve (ARR) dropping below 2300 MW. ERCOT deployed
1107 MW of Non-Spin Reserve Service (NSRS) at 16:45. EEA Level 1 was cancelled at 17:00.
The following operations report discusses primary and contributing factors leading up to and during the
EEA event and action items that ERCOT has taken in response to the event.
32
EEA-1June 23 2010
Executive Summary
At 15:19:54 on June 23rd, 2010, Unit A at the 138 kV Station A tripped causing the loss of approximately 733 MW of generation
due to the failure of the main power transformer high side ‘C’ phase disconnect switch.
At the same time, Circuit breakers CB1 and CB2 tripped at the 345 kV Station A. This opened one end of the 345 kV line from
Station A to Station B, isolating 482 MW of generation output of units B, C and D at Station B and these units tripped
approximately nine seconds later. Also, Unit E tripped at Station C causing the loss of 38 MW, for a total of 1253 MW.
Two 138 kV lines opened and automatically reclosed from Station A-Station D and Station A-Station E with no impact.
ERCOT ISO PI Data shows the frequency dropped to 59.709 Hz immediately after the trip at 15:19:54. After the event,
frequency recovered within 6 minutes and 32 seconds to its pre-disturbance value of 59.98 Hz at 15:26:26 and within 14 minutes
and 22 seconds to 60 Hz at 15:34:16.
ERCOT ISO Operators responded to this event as a NERC Disturbance Control Standard (DCS) event by instructing Load
acting as Resource (LaaRs) providing Responsive Reserve Service to deploy.
1150 MW of Generation Responsive Reserve was deployed (from 3281 MW of Adjusted Responsive Reserve (ARR) available).
These reserves were deployed at the beginning of the event, along with approximately 246 MW of LaaRs, which tripped on
under-frequency relay action. An additional 571 MW of LaaRs were deployed with VDIs between 15:31 and 15:34. A total of 817
MW of LAARs were deployed. Frequency recovered to 60 Hz at 15:34:16.
At 15:35 ERCOT implemented Level 1 of its Energy Emergency Alert (EEA). EEA Level 1 was declared because ERCOT’s ARR
dropped below 2300 MW. ERCOT deployed 522 MW of Non-Spin Reserve Service (NSRS) at 15:45:09. By 15:48:12 ARR was
above 2300 MW. At 16:00 all QSEs were instructed to restore all LAARs deployed. An additional 525 MW of NSRS was
deployed at 16:00:07 for a total of 1047 MW. EEA Level 1 was cancelled at 16:03.
33
EEA-1August 20 2010
Executive Summary
At approximately 15:25:48 on August 20th, 2010, unit A at the 345 kV Station A tripped causing the loss of approximately 1319 MW
of generation in the Houston area due to an inadvertent turbine trip signal initiated during planned surveillance testing.
Approximately eight seconds later, unit B at the 138 kV Station B tripped offline. At approximately 15:31:56 unit C tripped, and at
approximately 15:32:36 unit D tripped. The total loss of generation from this west Texas plant was approximately 212 MW.
ERCOT ISO Operations responded to this event as a NERC Disturbance Control Standard event; however it should be excluded
from compliance evaluation for being larger than the single largest contingency event. ERCOT ISO historical (PI) data indicates
that frequency dropped to approximately 59.749 Hz immediately after the first trip of unit A. The system frequency recovered to 60
Hz in approximately 4 minutes and 42 seconds (~15:30:30). ERCOT ISO recovered from the frequency deviation as required by
the NERC Reliability Standard BAL-002-0.
At 15:25:48, 1150 MW of Generation Responsive Reserve was deployed due to the low frequency. These reserves were deployed
at the beginning of the event, along with approximately 20 MW of Load acting as Resources (LaaRs), which tripped on underfrequency relay action. At 15:28 ERCOT ISO requested all Qualified Schedule Entities (QSE) to deploy all remaining LaaRs
scheduled to provide Responsive Reserve Service. A total of 1320 MW of LaaRs were deployed.
At 15:41, all QSEs were instructed to restore LaaRs. Non-Spinning Reserve Service (NSRS) was deployed at 15:44 in the
Houston zone for interval ending 16:15, and 15:45 in the South, North and West zones for interval ending 16:30. ERCOT ISO
implemented Level 1 of its Energy Emergency Alert (EEA) at 15:48 due to Adjusted Responsive Reserve (ARR) dropping below
2300 MW. By 16:13:38, ARR was above 2300 MW and EEA Level 1 was cancelled at 16:35.
The following operations report discusses primary and contributing factors leading up to and during the EEA event and action
items that ERCOT has taken in response to the event.
34
June 27th 2011 EEA - Frequency
35
June 27th 2011 EEA – Physical Responsive Capability
36
EEA-1Jan 18 2014
Executive Summary
The morning of January 18, 2014, ERCOT entered into emergency operations. This was the
result of a Disturbance Control Standard (DCS) qualifying event which occurred at
approximately 08:41. Nuke unit X tripped, resulting in approximately 1237 MW of energy being
lost to the grid shortly after the morning peak.
When the unit tripped, nearly 1000 MW of Physical Responsive Capability (PRC) was lost, as
PRC dropped from approximately 3300 MW to 2300 MW in approximately 90 seconds.
At approximately 08:47 ERCOT declared a Watch for PRC below 2500 MW, and then at
approximately 09:02 ERCOT declared Emergency Energy Alert (EEA) Level 1 for PRC below
2300 MW.
Off-Line Non-Spin was deployed between 08:44 and 10:18. Responsive Reserve Service (RRS)
from generators was also deployed as a result of the unit trip. Given that system frequency
reached approximately 59.699 Hz, approximately 850 MW of RRS from Load Resources was
provided from under-frequency relays. PRC was below 2300 MW for approximately 30 minutes,
below 2500 MW for approximately 38 minutes, and below 3000 MW for approximately 50
minutes.
At approximately 09:47 ERCOT exited EEA level 1 due to improving conditions, and resumed
normal operations. No firm load shed actions were taken.
37
Large Cap Unavail due to Forced Outage and Derate
• Example
• 2011
• 2014
38
A record-breaking arctic front was approaching prior to February 2, 2011
Extremely Cold Weather Grips Texas
February 1, 2011
The Coldest Week for North
Texas in 22 Years
The arctic cold front that descended on the Southwest during the first week
of February 2011 was unusually severe in terms of temperature, wind, and
duration of the event.
In many cities in the Southwest, temperatures remained below freezing for four days, and
winds gusted in places to 30 mph or more. The geographic area hit was also extensive,
complicating efforts to obtain power and natural gas from neighboring regions.
The storm, however, was not without precedent. There were prior severe cold weather events
in the Southwest in 1983, 1989, 2003, 2006, 2008, and 2010. The worst of these was in 1989,
the prior event most comparable to 2011.
39
More than 8,000 megawatts (MW) of generation unexpectedly dropped offline overnight
65,000
Committed Generation vs. Committed Generation minus Forced
Outages on February 2, 2011
60,000
55,000
MW
50,000
45,000
40,000
Committed Generation
Time
Committed Generation minus Forced Outages
40
The ERCOT System responded as expected Feb 2nd 2011
Frequency vs. Load Shed
60.10
60.05
60.00
59.95
59.90
59.85
59.80
2,000 MW Firm
Load Shed @ 6:23
HZ
59.75
59.70
59.65
59.60
Load Resources
Shed @ 5:20
1,000 MW Firm
Load Shed and
Emergency
Interruptible Load
@ 5:44
59.55
59.50
1,000 MW Firm
Load Shed @ 6:04
59.45
Frequency
41
A timeline of the emergency steps that were taken leading to rotating outages
in ERCOT Feb 2nd 2011
Issued EEA 3
• EILS deployed
• Firm Load Shed
1,000 MW
1,804 MW
Non-Spin
deployed
4:30am
5:43am
FEB 2
5:08am
New winter Peak
Record
7:57am
Restored 500 MW
(3,500 MW out)
8:22am
Restored 500 MW
(3,000 MW out)
9:25am
Restored 500 MW
(2,500 MW out)
Move to EEA 2B
56,480 MW
From EEA 3
Restored 500 MW
Restoration
Complete
1:07pm
2:01pm
7:15pm
FEB 3, 10 AM EEA 2A ENDS & EILS RECALLED
5:20am
6:04am
11:39am
Issued EEA 2A
Firm load shed 1,000 MW
(2,000 MW total)
Restored 500 MW
(2,000 MW out)
• Reserves below
1,750 MW
6:05am
12:04pm
• Load Resources
deployed
Frequency 59.576Hz
6:23am
Restored 500 MW
(1,500 MW out)
Firm Load Shed 2,000 MW
12:25pm
(4,000 MW total)
Restored 500 MW
(1,000 MW out)
Issued Watch
6:59am
Reserves below
2,500 MW
Media Appeal issued
1:57pm
3:14pm
Move to EEA 2A
Load
Resources
Recalled
From EEA 2B
12:49pm
Restored 500 MW
(500 MW out)
42
Event Summary – January 6, 2014
• At 6:52, ERCOT declared Level 1 of its Energy Emergency Alert
(EEA) and declared EEA Level 2 at 7:01, primarily due to the loss of a
number of generating units
• Non-Spin Reserve Service (NSRS), Load Resources (LR) and
Emergency Response Service (ERS) were deployed, but firm load
shed was not required
• ERCOT moved from EEA2 to EEA1 at 7:51 and resumed normal
operations at 9:12
• Generation outages & derates peaked at 9355 MW just before 07:00,
with 3541 MW due to weather
• Hourly peak demand was 55,487 MW for HE08 and instantaneous
peak demand was 56,478 MW at 07:08:24
43
Timeline – January 6, 2014 EEA
ERCOT issued EEA
Level 1 for PRC
below 2300 MW
ERCOT issued
EEA Level 2 for
PRC below 1750
MW
Watch issued
due to PRC
below 2500
MW
06:37 AM
06:42 AM
06:52 AM
06:42 AM
06:52 AM
07:01 AM
07:51 AM
ERCOT recalled
EEA Level 2. EEA
Level 1 remains
in effect
07:56 AM
ERCOT recalled
30 minute ERS
07:58 AM
ERCOT recalled
10 minute ERS.
06:57 AM
07:02 AM
ERCOT deployed
Non-Spin for 187
MW
ERCOT
deployed
Group 1 RRS
for 546.36 MW
ERCOT deployed RRS to
Generators for frequency
below 59.91 Hz
ERCOT deployed
Group 2 RRS for
536.24 MW
ERCOT deployed
30 minute ERS
for 111.68 MW
07:05 AM
07:43 AM
ERCOT deployed
10 minute ERS
for 508.72 MW
07:13 AM
ERCOT recalled
all RRS from
Generators due
to frequency
above 59.91 Hz
ERCOT recalled
all Group 2 RRS
07:50 AM
ERCOT recalled
all Group 1 RRS
EEA Level 1
cancelled. Watch
remains in effect.
Watch terminated
as PRC was above
3000 MW
09:12 AM
09:55 AM
08:10 :36 AM
ERCOT recalled all NonSpin
08:10:48 AM
ERCOT deployed RRS
to Generators for
frequency below 59.91
Hz
08:17 AM
ERCOT recalled all RRS
from Generators due
to frequency above
59.91 Hz
44
Reserves
45
High Summer Demand
• Example
• 2011
46
2011 High Load Summer Energy Emergency Alerts
August 2011
Sunday
Monday
Tuesday
Wednesda Thursda
y
y
Friday
Saturday
31
1
2
3
5
6
EEA 1
4
EEA 1
EEA
2B
EEA 1
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
1
2
3
EEA 1
28
29
30
EEA 2A
31
47
August 2011 Peak Loads
8/3: Record Peak
48
ERCOT Load, Wind, and PRC 8/4/2011 12:00–24:00
49
Wind Forecast/Ramp
• Example
• Feb 26, 2008
50
EECP Feb 26 2008 Issues identified in March 17 Wind Workshop
Wind Output, T wo Wind P ower F orec as ts , and Day-A head R es ourc e P lan MW for
2/26/08
MAP E
3500
50% WP F : 20.80%
80% WP F : 25.32%
MW
3000
2500
Hour Aver. Ac tual
O utput
2000
* 50% W ind P ower
F orec as t
1500
* 80% W ind P ower
F orec as t
R es ourc e P lan MW
from W G R s in
D ay-Ahead
1000
500
0
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
H our E nding
51
Summary of some issues noted back in Zonal system related to Wind
issues from 2008
• ERCOT offsets for known differences in actual output and scheduled
output
• Resource Plan errors can cause the hour ahead study to indicate
capability that is not available.
– Resource Plans and Schedules should be updated often with the
latest and best information
• Deployments for Wind Resources should be considered from actual
output and not scheduled output.
• Abrupt generation changes tax regulation and adversely affect
frequency.
• ERCOT should consider a ramp rate limit requirement for following
deployment instructions. For example a 5% limit for a 500 MW unit
would mean the unit should not ramp faster than 25 MW/min.
• Implement an ERCOT wide forecast for wind and require this to be
used for Resource Plans
52
Unseasonable Weather during maint. season
• Example
• April 17, 2006
53
Load Forecast Issues 04-17-06
• Load forecast was lower than actual loads
– Peak load would have been ~ 53,817 MW if load had not been
interrupted (actual was 51,613 MW)
– All-time April peak was 49,280 MW in late April 2002
– April 17 Peak Load forecasts
• 49,018 MW @16:00 April 16
• 49,591 MW @01:00 April 17
• 51,114 MW @13:00 April 17
• Why?
– Temperature forecast for DFW area was 5° low (95° vs 100°)
• Accounts for about 1,000 - 1,500 MW error
– Parameter set incorrectly to adjust for past actual loads (fixed)
– Low load forecast for Coast (Houston) area (under investigation)
54
Resource Plan/Available Capacity Issues 04-17-06
• The Resource Plan used for the 13:00 April 17 Replacement
Study showed 55,283 MW of maximum generating capacity online at peak
– Operator saw no problem meeting 51,114 MW forecast
– Would have been enough to cover 53,817 MW load plus
1,150 Responsive Reserve on units, but not by much
– Judgment call on whether to call an Alert if forecast had
been 53,817 MW
• However, Resource Plans at 13:00 for peak hour:
– Showed 793 MW that had tripped before 13:00 or was
started late (after 16:00)
– Included 1,683 MW capacity that tripped between 15:51 and
16:17
55
What if? 04-17-06
• Peak load forecast used for the 16:00 April 16 Replacement
Study had been 53,817 MW instead of 49,018 MW
– An additional 1,026 MW of capacity off-line at peak April 17
would have been procured
– Given actual unit trips, would have still been in EECP
– Might have avoided Step 4, but would have been close
• Units had not tripped or started late
– Might have avoided EECP altogether, but would have been
close
56
Reference ERCOT reports
•
•
•
•
•
•
•
•
•
•
•
•
2006 EECP4 http://www.ercot.com/content/meetings/ros/keydocs/2006/0515/Review_of_EECP_Event_050806_jd.ppt
2008 Wind http://www.ercot.com/calendar/2008/03/20080317-WIND
2010
http://www.ercot.com/content/meetings/ros/keydocs/2010/0610/06._ERCOT_OPERATIONS_REPORT_EEA_051510_Public
.doc
http://www.ercot.com/content/meetings/ros/keydocs/2010/0715/07._ERCOT_OPERATIONS_REPORT_EEA_Level_1_0623
10_public_rev3.doc
http://www.ercot.com/content/meetings/ros/keydocs/2010/0916/06._ERCOT_OPERATIONS_REPORT_EEA_Level_1_0820
10_public.doc
2011
http://www.ercot.com/content/news/presentations/2011/Senate_EEA_Presentationfinaltg.pdf
http://www.ercot.com/content/meetings/ros/keydocs/2011/0915/05._ERCOT_Operations_Report_EEA_Events_080211080511_public.doc
http://www.ercot.com/content/meetings/ros/keydocs/2011/0915/05._ERCOT_Operations_Report_EEA_August_23_24_Publi
c.doc
2014
http://www.ercot.com/content/meetings/ros/keydocs/2014/0306/07._Jan_6_EEA_ROS_Report.ppt
http://www.ercot.com/content/committees/board/keydocs/2014/ERCOT_Monthly_Operational_Overview_201401.pdf
57
Questions?
Current Ancillary Services
Bill Blevins
59
Ancillary Service
A service necessary to support the transmission of energy to
Loads while maintaining reliable operation of the
Transmission Service Provider’s (TSP’s) transmission
system using Good Utility Practice. Following are the
Ancillary Service capacity products within ERCOT:
1. Responsive Reserve Service
2. Regulation Service
3. Non-Spinning Reserve Service
60
Responsive Reserve Service
An Ancillary Service that provides operating reserves that is
intended to:
1. Arrest frequency decay within the first few seconds of a
significant frequency deviation on the ERCOT
Transmission Grid using Primary Frequency Response
and interruptible Load;
2. After the first few seconds of a significant frequency
deviation, help restore frequency to its scheduled value
to return the system to normal;
3. Provide energy or continued Load interruption during the
implementation of the EEA; and
4. Provide backup regulation.
61
Responsive Reserve Service
1. RRS may be provided through one or more of the
following means:
a) By using frequency-dependent response from OnLine Resources as prescribed in the Operating
Guides to help restore the frequency within the first
few seconds of an event that causes a significant
frequency deviation in the ERCOT System; and
b) Either manually or by using a four-second signal to
provide energy on deployment by ERCOT
2. RRS Service may be used to provide energy during the
implementation of an EEA. Under the EEA, RRS
provides generation capacity, capacity from Controllable
Load Resources or interruptible Load available for
deployment on ten minutes’ notice.
62
Responsive Reserve Service
RRS Service may be provided by:
1. Unloaded, On-Line Generation Resource capacity;
2. Load Resources controlled by high-set, under-frequency
relays;
3. Controllable Load Resources;
4. Hydro Responsive Reserves as Synchronous
Condenser Fast Response Mode; and
5. Direct Current Tie (DC Tie) response that stops
frequency decay as defined in the Operating Guides.
63
Responsive Reserve Service
Responsive Reserve (RRS) Service is a service used to
restore or maintain the frequency of the ERCOT System:
1. In response to, or to prevent, significant frequency
deviations;
2. As backup Regulation Service; and
3. By providing energy during an Energy Emergency
Alert (EEA):
• When PRC < 1750 MW or unable to maintain system
frequency at 60 Hz;
• RRS from Generation Resources is deployed automatically at
59.91 Hz as calculated from the EMS
64
Regulation Service
1. An Ancillary Service that consists of either Regulation
Down Service (Reg-Down) or Regulation Up Service
(Reg-Up)
An Ancillary Service that provides capacity that can respond to
signals from ERCOT within five seconds to respond to changes in
system frequency.
2. Fast Responding Regulation Service (FRRS)
A subset of Regulation Service that consists of either Fast
Responding Regulation Down Service (FRRS-Down) or Fast
Responding Regulation Up Service (FRRS-Up):
a)
b)
Provides Reg-Up capacity to ERCOT within 60 cycles of either its
receipt of an ERCOT Dispatch Instruction or
Its detection of a trigger frequency independent of an ERCOT Dispatch
Instruction.
65
Regulation Service
1. ERCOT methodology aims to procure enough
regulation so that regulation is not exhausted more than
1.2% of the time
2. Greater of the adjusted 98.8th percentile deployed
regulation value from the previous year and the 98.8th
percentile value from the previous 30 days is used to
determine the initial requirement
3. During the previous 30 days, if the exhaustion rate of
Regulation significantly exceeded the desired 1.2% for
any hour, additional MWs are added for that hour in
order to achieve 1.2%
4. ERCOT will add incremental MWs to Regulation to
account for increased installed wind capacity
5. ERCOT will also procure additional Regulation during
hours in which CPS1 scores are not above the desired
threshold of 100%
66
Non-Spin Service Deployment
ERCOT may deploy Non-Spin, which has not been deployed as part of a
standing On-Line Non-Spin deployment, under the following conditions:
1.
2.
3.
4.
5.
When (HASL – Gen) – (30-minute load ramp) < 0 MW, deploy half of the
available Non-Spin capacity.
When (HASL – Gen) – (30-minute load ramp) < -300 MW, deploy all of
the available Non-Spin capacity.
When PRC < 2500 MW, deploy all of the available Non-Spin capacity.
When the North-to-Houston (N_H) Voltage Stability Limit Reliability
Margin < 300 MW, deploy Non-Spin (all or partial) in the Houston area
as needed to restore reliability margin.
When Off-Line Generation Resources providing Non-Spin are the only
reasonable option available to the Operator for resolving local issues,
deploy available Non-Spin capacity on only the necessary individual
Resources.
Note : On-line Non-Spin capacity always remains available for SCED to
dispatch.
http://www.ercot.com/content/mktrules/guides/procedures/NonSpinning%20Reserve%20Service%20Deployment%20and%20Recall%20Procedure.zip
67
Ancillary Service Deployment
NSPIN
Capacity
Reserved
for AS
RRS
HSL – High Sustainable
Limit
Capacity reserved by
generator for Non-Spin
and Responsive to be
released to SCED when
deployed by ERCOT
•
SCED dispatches generation between HASL
and LASL (SCED Room).
•
Resource not providing AS:
RGU
HASL – High Ancillary
Service Limit
•
-
HASL = HSL
-
So SCED can dispatch the unit up to HSL
Resource providing AS:
-
SCED
ROOM
GEN
Regulation
deployed every
4 seconds to
balance
generation
with load
LASL – Low Ancillary Service Limit
RGD
LSL – Low Sustainable Limit
-
-
HASL= HSL – RGU- RRS – NSPIN
Resource reserves part of the capacity for providing AS
(makes capacity unavailable for SCED)
Regulation is deployed as needed every 4 seconds to
maintain balance between generation and load
Responsive reserve and Non-spin are deployed when
required and the capacity reserved by the resource for
RRS and NSPIN is released SCED to be economically
dispatched
RRS MWs are offered at the System Wide Offer Cap
(Currently $5,000 will be $7000 beginning June 1,
2014)
Non-Spin MWs has to be offered at a minimum of $120
for Online NSRS or $180 for offline NSRS (once NPRR
576 is effective, NSRS has to be offered ≥ $75)
68
Questions?
Managing Constraints in EEA
Chad Thompson
70
Background
• NPRR480 removed overarching language
that allowed ERCOT to “relax” transmission
constraints during emergency operations
• During recent EEA events, some generation
has been limited as a result of binding
constraints in SCED
• A mechanism is needed to allow generation
capacity to be available to SCED during
emergency operations in a manner that does
not reduce transmission reliability
• The following slides apply only to those
constraints that may limit generation
71
NPRR480 Removed Language
• 6.5.9.1 Emergency and Short Supply Operation,
(3) “…Under an Emergency Condition, the
ERCOT Operator may relax transmission
constraints to provide additional generation at the
expense of temporarily creating a security violation
as long as the violation does not physically
overload any single Transmission Element above
its emergency limit, as defined in the ERCOT
Operating Guides...”
• Rationale
– Attachment 1-EOP-002-2 of NERC Reliability
Standard EOP-002-3 does not support the relaxation
of constraints during EEA
72
Re-Evaluation
• Attachment 1-EOP-002 has provisions during
EEA2 that allows the RC to review its SOLs
and IROLs through consultation with the
impacted BA and Transmission Provider
about the possibility of revising SOLs
• During EEA3 there is a provision to revise
SOLs and IROLs as allowed by the BA or
TOP whose equipment is at risk, subject to
considerations outlined in Attachment 1
• BUT, it does not say that the RC can stop
managing congestion on the grid
73
Attachment 1 - EOP-002-3
• 2.4 Evaluating and mitigating transmission limitations
– The Reliability Coordinators shall review all System Operating
Limits (SOLs) and Interconnection Reliability Operating Limits
(IROLs) and transmission loading relief procedures in effect that
may limit the Energy Deficient Entity’s scheduling capabilities.
Where appropriate, the Reliability Coordinators shall inform the
Transmission Providers under their purview of the pending
Energy Emergency and request that they increase their ATC by
actions such as restoring transmission elements that are out of
service, reconfiguring their transmission system, adjusting phase
angle regulator tap positions, implementing emergency operating
procedures, and reviewing generation redispatch options.
• 2.4.4 Initiating inquiries on reevaluating SOLs and IROLs
– The Reliability Coordinators shall consult with the Balancing
Authorities and Transmission Providers in their Reliability Areas
about the possibility of reevaluating and revising SOLs or IROLs.
74
Attachment 1 - EOP-002-3
•
3.4 Reevaluating and revising SOLs and IROLs
– The Reliability Coordinator of the Energy Deficient Entity shall evaluate the risks of
revising SOLs and IROLs on the reliability of the overall transmission system.
Reevaluation of SOLs and IROLs shall be coordinated with other Reliability
Coordinators and only with the agreement of the Balancing Authority or Transmission
Operator whose equipment would be affected. The resulting increases in transfer
capabilities shall only be made available to the Energy Deficient Entity who has
requested an Energy Emergency Alert 3 condition. SOLs and IROLs shall only be
revised as long as an Alert 3 condition exists or as allowed by the Balancing Authority
or Transmission Operator whose equipment is at risk. The following are minimum
requirements that must be met before SOLs or IROLs are revised:
•
3.4.1 Energy Deficient Entity obligations
– The deficient Balancing Authority or Load Serving Entity must agree that, upon
notification from its Reliability Coordinator of the situation, it will immediately take
whatever actions are necessary to mitigate any undue risk to the Interconnection.
These actions may include load shedding.
•
3.4.2 Mitigation of cascading failures
– The Reliability Coordinator shall use its best efforts to ensure that revising SOLs or
IROLs would not result in any cascading failures within the Interconnection.
75
Re-Evaluation
• What does this mean?
– ERCOT has the ability to change the SOLs it
controls to during EEA3, after consultation
(presumably which occurred before, or during
EEA2) with the impacted transmission
companies
– The SOLs utilized must not result in
cascading failures or otherwise jeopardize
safety or public well-being
– ERCOT cannot simply “stop constraining”
because the generation behind a constraint is
being limited
76
Re-Evaluation
• What about CMPs?
– CMPs should continue to be developed and
utilized when applicable; however the necessary
review time is generally longer than what may be
available during an EEA
– In general, CMPs are developed day-ahead or
earlier, and while some TOAPs are developed in
real-time, analysis and implementation of CMPs
during EEA conditions may not be attainable in
the timeframe of the EEA
– Constraints that limit generation tend to be
getaway issues where reducing generation is the
only means for relieving the SOL
77
Potential Topics for Discussion
• NPRR or NOGRR which provides a
mechanism for utilizing the transmission
system to its fullest extent during
emergency operations in a manner that
maximizes generation delivery without
negatively impacting reliability
– Interim solution would be operator procedure
modifications ahead of a market rules change
– Mechanism cannot risk operators’ ability to
manage overall system reliability during EEA
78
Potential Topics for Discussion
• During non-EEA Conditions
– SCED used to manage congestion consistent with
current practices
• During a Watch Condition for PRC below 2500
MW
– SCED used to manage congestion consistent with
current practices
– ERCOT and TOs evaluate both active and binding
constraints which ERCOT identifies as potentially
limiting generation, and discuss the potential for
operating to the 15-Minute Rating, if available, in the
event ERCOT enters EEA3
– Recall outages associated with constraints that may
be limiting generation, where possible
79
Potential Topics for Discussion
• During EEA1 Conditions
– SCED used to manage congestion consistent
with current practices
– ERCOT and TOs review double-circuit
contingency impacts and consider use of
single-circuit contingencies as alternates
• During EEA2 Conditions
– SCED used to manage congestion consistent
with current practices
80
Potential Topics for Discussion
• During EEA3 Conditions
– ERCOT may control to a different facility rating,
(e.g. 15-Minute Rating) in SCED where
appropriate, based on the results of the
evaluation with TOs during the Watch, so long as
control to the alternative facility rating does not
result in any cascading failures or otherwise
jeopardize safety or public well-being
– During transition from EEA3 back to EEA2 or
EEA 1, ERCOT and TOs will revert back to
“standard” congestion practices in a manner that
supports reliability, coordinated by the ERCOT
and TO System Operators
81
Stability Limits and IROLs
• Management of stability limits and IROLs
in SCED will not change during EEA
conditions
82
Questions?
Identify Issues
Chad Thompson
84
Identify Issues
•
•
•
•
•
HASL Release
Constraint Management
PRC As A Trigger
Wind Variability
Review Issues Identified During Workshop
85
HASL Release
• Manual deployment of all RRS
• OBD Changes to Non-Spin deployment
• SCR to create an “EEA button” to
automatically deploy all AS though the
EMS
86
PRC As A Trigger
• How we got to PRC
– April 17 2006 & ARRS
• Why 2300 MW
• Should PRC be replaced with something
else?
– Should Load Resources & Synchronous
condensers be considered in the
calculations?
87
Wind Variability
• Consider turbine shut down temperatures
in Wind Forecast
• “Icing Forecast?”
• Consider ramp event predictions in RUC
Process
88
Next Steps
Dan Woodfin
89