Transcript Available Transfer Capability

TTC/ATC Computations
and
Ancillary Services
in the Indian context
Outline
•
Part A:
TTC/ATC computations
• Transfer Capability - Definition
• Relevance of transfer capability in Indian electricity market
• Difference between Transfer capability and Transmission
Capacity
• Assessment of Transfer Capability
• Ratio of transfer capability to transmission capacity
• Congestion
•
Part B:
Ancillary services in the Indian context
Part A
Total Transfer Capability (TTC)/
Available Transfer Capability (ATC)
computations
Transfer Capability Definitions
North American Electric Reliability
Corporation’s (NERC) definition of TTC
• The amount of electric power that can be moved or
transferred reliably from one area to another area of the
interconnected transmission systems by way of all
transmission lines (or paths) between those areas under
specified system conditions……….16-Mar-2007(FERC)
•
As per 1995 document of NERC, following conditions need to be
satisfied:
– all facility loadings in pre-contingency are within normal ratings and
all voltages are within normal limits
– systems stable and capable of absorbing the dynamic power swings
– before any post-contingency operator-initiated system adjustments
are implemented, all transmission facility loadings are within
emergency ratings and all voltages are within emergency limits”
5
European Network of Transmission System Operators’
definition of Total Transfer Capability (TTC)
• “TTC is that maximum exchange programme between
two areas compatible with operational security
standards’ applicable at each system if future network
conditions, generation and load patterns were perfectly
known in advance.”
• “TTC value may vary (i.e. increase or decrease) when
approaching the time of programme execution as a
result of a more accurate knowledge of generating unit
schedules, load pattern, network topology and tie-line
availability”
6
Total Transfer Capability as defined in the
IEGC and Congestion charge Regulations
• “ Total Transfer Capability (TTC)” means the
amount of electric power that can be transferred
reliably over the inter-control area transmission
system under a given set of operating conditions
considering the effect of occurrence of the worst
credible contingency.
Available Transfer Capability as defined in the
IEGC and Congestion charge regulations
• “ Available Transfer Capability (ATC) ” means the
transfer capability of the inter-control area transmission
system available for scheduling commercial transactions
(through long term access, medium term open access
and short term open access) in a specific direction,
taking into account the network security. Mathematically
ATC is the Total Transfer Capability less Transmission
Reliability Margin.
Simultaneous TTC
Area A
Area C
2000 MW
4000 MW
Area B
5000 MW
9
Relevance of Transfer Capability
in
Indian Electricity Market
Open Access in Inter-state Transmission
Regulations, 2008
• 3( 2) The short-term open access allowed after
long / medium term by virtue of– (a) inherent design margins;
– (b) margins available due to variation in power flows;
and
– (c) Margins available due to in-built spare
transmission capacity created to cater to future load
growth or generation addition.]
Tariff Policy Jan 2006
7.3 Other issues in transmission
(2)
All available information should be shared with the
intending users by the CTU/STU and the load dispatch
centres, particularly
information on available
transmission capacity and load flow studies.
Open Access Theory & Practice
Forum of Regulators report, Nov-08
“For successful implementation of OA, the
assessment of available transfer capability
(ATC) is very important. A pessimistic
approach in assessing the ATC will lead to
under utilisation of the transmission system.
Similarly, over assessment of ATC will place
the grid security in danger.”
13
Declaration of Security Limits
• “ In order to prevent the violation of security
limits, System Operator SO must define the
limits on commercially available transfer capacity
between zones.” CIGRE_WG_5.04_TB_301
• “System Operators try to avoid such unforeseen
congestion
by
carefully
assessing
the
commercially available capacities and reliability
margins.” CIGRE_WG_5.04_TB_301
14
Reliability Margin
NERC definition of Reliability Margin
(RM)
•
Transmission Reliability Margin (TRM)
– The amount of transmission transfer capability necessary to provide
reasonable assurance that the interconnected transmission network will
be secure. TRM accounts for the inherent uncertainty in system
conditions and the need for operating flexibility to ensure reliable system
operation as system conditions change.
•
Capacity Benefit Margin (CBM)
– The amount of firm transmission transfer capability preserved by the transmission
provider for Load-Serving Entities (LSEs), whose loads are located on that
Transmission Service Provider ’ s system, to enable access by the LSEs to
generation from interconnected systems to meet generation reliability
requirements. Preservation of CBM for an LSE allows that entity to reduce its
installed generating capacity below that which may otherwise have been
necessary without interconnections to meet its generation reliability requirements.
The transmission transfer capability preserved as CBM is intended to be used by
the LSE only in times of emergency generation deficiencies.
16
Quote on Reliability Margin
from NERC document
• “The beneficiary of this margin is the “larger
community” with no single, identifiable group of
users as the beneficiary.”
• “The benefits of reliability margin extend over a
large geographical area.”
• “They are the result of uncertainties that cannot
reasonably be mitigated unilaterally by a single
Regional entity”
17
ENTSOE definition of Reliability Margin
• “ Transmission Reliability Margin TRM is a security
margin that copes with uncertainties on the computed
TTC values arising from
– Unintended deviations of physical flows during operation due to
physical functioning of load-frequency regulation
– Emergency exchanges between TSOs to cope with unexpected
unbalanced situations in real time
– Inaccuracies in data collections and measurements”
18
Reliability margin as defined in Congestion
charge regulations
• “Transmission Reliability Margin (TRM)” means
the amount of margin kept in the total transfer
capability necessary to ensure that the
interconnected transmission network is secure
under a reasonable range of uncertainties in
system conditions;
Distinguishing features of Indian
grid
• Haulage of power over long distances
• Resource inadequacy leading to high uncertainty in adhering to
maintenance schedules
• Pressure to meet demand even in the face of acute shortages and
freedom to deviate from the drawal schedules.
• A statutorily permitted floating frequency band of 49.5 to 50.2 Hz
• Non-enforcement of mandated primary response, absence of
secondary response by design and inadequate tertiary response.
• No explicit ancillary services market
• Inadequate safety net and defense mechanism
20
Reliability Margins- Inference
• Grid Operators’ perspective
– Reliability of the integrated system
– Cushion for dynamic changes in real time
– Operational flexibility
• Consumers’ perspective
– Continuity of supply
– Common transmission reserve to take care of contingencies
– Available for use by all the transmission users in real time
• Legitimacy of RMs well documented in literature
• Reliability Margins are non-negotiable
21
Difference between Transfer
Capability and Transmission
Capacity
Transmission Capacity Vis-à-vis Transfer Capability
Transmission Capacity
Transfer Capability
1
Declared by designer/ manufacturer
Declared by the Grid Operator
2
Is a physical property in isolation
Is a collective behaviour of a system
3
Depends on design only
Depends on design, topology, system
conditions, accuracy of assumptions
4
Deterministic
Probabilistic
5
Constant under a set of conditions
Always varying
6
Time independent
Time dependent
7
Non-directional (Scalar)
Directional (Vector)
8
Determined directly by design
Estimated indirectly using simulation
models
9
Independent of Parallel flow
Dependent on flow on the parallel path
Transfer Capability is less than transmission
capacity because
• Power flow is determined by location of injection, drawal
and the impedance between them
• Transfer Capability is dependent on
–
–
–
–
–
Network topology
Location of generator and its dispatch
Pont if connection of the customer and the quantum of demand
Other transactions through the area
Parallel flow in the network
• Transmission Capacity independent on all of the above
• When electric power is transferred between two areas
the entire network responds to the transaction
77% of electric power transfers
from
Area A to Area F
will flow on the transmission path
between Area A & Area C
Assume that in the initial
condition, the power flow from
Area A to Area C is 160 MW on
account of a generation dispatch
and the location of customer
demand on the modeled
network.
When a 500 MW transfer is
scheduled from Area A to Area F,
an additional 385 MW (77% of
500 MW) flows on the
transmission path from
Area A to Area C, resulting in a
545 MW power flow from
Area A to Area C.
Assessment of
Transfer Capability
Transfer Capability Calculations must
• Give a reasonable and dependable indication of transfer
capabilities,
• Recognize time variant conditions, simultaneous transfers,
and parallel flows
• Recognize the dependence on points of injection/extraction
• Reflect regional coordination to include the interconnected
network.
• Conform to reliability criteria and guides.
• Accommodate reasonable uncertainties in system conditions
and provide flexibility.
Courtesy: Transmission Transfer Capability Task Force, "Available Transfer Capability Definitions and
Determination", North American Electric Reliability Council, Princeton, New Jersey, June 1996 NERC
27
Europe
• Increase generation in one area and lower it in the other.
• A part of cross border capacity is withdrawn from the
market to account for
– Random threats to the security of the grid, such as loss of a
generating unit. This capacity is called as Transmission
Reliability Margin (TRM)
– TRM based on the size of the biggest unit in the synchronous
area and the domestic generation peak of a control area.
• Net Transfer Capacity = TTC – TRM
– published twice a year (winter and summer)
United States
• The commercial capacity available for market
players is calculated by deducting Transmission
Reliability Margin (TRM) and Capacity Benefit
Margin (CBM) from Total Transfer Capability
– TRM is set aside to ensure secure operation of the
interconnected transmission network to accommodate
uncertainties in system operations while CBM is set
aside to ensure access to generation from
interconnected systems to meet generation reliability
requirements.
Total Transfer Capability: TTC
Thermal Limit
Power
Flow
Voltage Limit
Stability Limit
Total Transfer Capability
Time
Total Transfer Capability is the minimum of the
Thermal Limit, Voltage Limit and the Stability Limit
30
Intra-day STOA
Day-ahead STOA
Collective (PX) STOA
First Come First Served STOA
Advance Short Term Open Access (STOA)
TTC ATC
Medium Term Open Access (MTOA)
Long Term Access (LTA)
Reliability Margin (RM)
RM
Available Transfer Capability is
Total Transfer Capability less Reliability Margin
31
Transfer Capability assessment
Trans.
Plan +
approv.
S/D
LGBR
Last
Year
Reports
Weather
Forecast
Last
Year
pattern
Anticipated
Network topology +
Capacity additions
Anticipated
Substation Load
Anticipated
Ex bus
Thermal Generation
Planning
criteria
Credible
contingencies
Simulation
Total Transfer
Capability
Analysis
less
Brainstorming
Reliability
Margin
equals
Anticipated Ex bus
Hydro generation
Operating
limits
Operator
experience
Planning Criteria is strictly followed during simulations
Available
Transfer
Capability
32
32
Ampacity
Ampacity
More than 10 years of age
65 degree conductor
75 degree conductor
Conductor Type
40o ambient
10o ambient
40o ambient
10o ambient
ACSR Bersimis
693
1476
945
1601
ACSR Moose
575
1240
799
1344
ACSR Zebra
527
1071
718
1161
ACSR Twin Moose
1150
2479
1598
2687
ACSR Quad Moose
2300
4958
3196
5374
ACSR Quad
Bersimis
2773
5905
3779
6403
ACSR Triple
Snowbird
1725
3719
2397
4031
For bundled conductors
Thermal limit derived from ampacity
Thermal limit in MW at 0.975 pu voltage and unity
p.f.
More than 10 years of age
65 degree conductor
Conductor Type
75 degree conductor
40o
40o
ambient 10o ambient ambient
10o ambient
400 kV ACSR Twin Moose
777
1675
1079
1815
400 kV ACSR Quad Moose
1554
3349
2159
3630
400 kV ACSR Quad
Bersimis
1873
3989
2553
4325
400 kV ACSR Triple
Snowbird
1165
2512
1619
2723
220 kV ACSR Zebra
196
398
267
431
Permissible Line Loading Limits
From Sec 4.1 of Transmission Planning Criteria
• SIL at certain voltage levels modified to account for
 Shunt compensation
 k1 = sqrt (1- degree of shunt compensation)
 Series compensation
 k2 = 1 / [sqrt (1-degree of series compensation)
 Variation in line loadability with line length
 K3
From Sec 4.2 of Transmission Planning Criteria
• Thermal loading limits at conductor temperature of 75o
• Ambient 40o in summer and 10o in winter
35
1
Line length
386
in kilometer
2
From end shunt reactor in MVAr at 400 kV
72.56
80 MVAr 420 kV
3
To end shunt reactor in MVAr at 400 kV
72.56
80 MVAr 420 kV
4
Surge Impedance Loading (SIL)
515
in MW
Conductor type
ACSR Twin
Moose
75o C design conductor
temperature and age >10
years
Line reactance (X)
0.0002075
Per unit / kilometer / circuit
Line susceptance (B)
0.0055
Per unit / kilometer / circuit
Base MVA
100
9
Power transfer between adjacent buses at 5 % voltage
regulation and 30 deg angular separation = PB
593
(in MW)
10
Total shunt compensation for the line in MVAr
145
Sl. No. (2) + (3)
11
Line charging MVAr
212
Line length X B x Base MVA =
Sl. No. (1) x (7) x (8)
12
Degree of shunt compensation = Dsh
0.68
Sl No. (10)/ (11)
13
Degree of series compensation = Dse
0.35
35 % Fixed compensation
14
Multiplying factor-1 (shunt compensation) = k1
0.56
Sqrt(1-Dsh)
15
Multiplying factor-2 (series compensation) = k2
1.24
1/ Sqrt (1-Dse)
16
Multiplying factor-3 (St. Clair’s line loadability) = k3
1.15
PB / SIL
17
Permissible line loading PL
414
SIL x k1 x k2 x k3
18
Ampacity of the conductor in summer conditions
1598
at ambient temperature of 40o C
19
Thermal limit (MW) in summer = Pth_summer
1079
at 0.975 pu voltage and unity p.f.
20
Operating limit (in MW) in summer
414
36
Min of PL and Pth_summer
5
6
7
8
Illustration of
calculation of
operating limits
of transmission
line
Steady State Voltage Limits
Voltage (kV rms)
Nominal
Maximum
Minimum
765
800
728
400
420
380
220
245
198
132
145
122
37
Credible contingencies
• From Section 3.5 of IEGC
–
–
–
–
–
–
Outage of a 132 kV D/C line or
Outage of a 220 kV D/C line or
Outage of a 400 kV S/C line or
Outage of a single ICT or
Outage of one pole of HVDC bi pole or
Outage of 765 kV S/C line
without necessitating load shedding or rescheduling
of generation during steady state operation
38
Input Data and Source
S No.
Input Data
Suggested Source
1
Planning Criteria
Manual on Transmission Planning Criteria issued by CEA
2
Network Topology
Existing network with full elements available
Planned outages during the entire assessment period
New transmission elements expected
3
Transmission line limits
Minimum of thermal limit, stability limit and voltage limit
4
Thermal unit availability
Load Generation Balance report, Maintenance schedule
Anticipated new generating units
5
Thermal despatch
Ex bus after deducting the normative auxiliary consumption
Output could be further discounted by the performance index of
generating units of a particular size as compiled by CEA
6
Gas based thermal
despatch
Past trend
7
Hydro despatch
Peak and off peak actual hydro generation on median
consumption day of same month last year
The current inflow pattern to be duly accounted
8
Load
Anticipated load
9
Credible contingencies
Planning criteria + Operator experience
39
Process for assessment
• Base case construction (The biggest
challenge)
– Anticipated network representation
– Anticipated load generation
– Anticipated trades
• Simulations
– Increase generation in exporting area with
corresponding decrease in importing area till
network constraint observed
40
4
NORTHERN
REGION
2
NORTHEASTERN
REGION
WESTERN
REGION
8
16
EASTERN
REGION
4
SOUTHERN
REGION
WR Grid
NR
NR
ER
ER
SR
Case 1
Case 3
SR
NR
Case4
NR
Case 2
ER
ER
SR
SR
WR Grid
NR
NR
Case 5
ER
ER
Case 6
SR
SR
NR
Case 7
NR
ER
Case 8
Possible scenarios for Western Regional Grid
Sl.NO.
NR
ER
SR
Work out from this case
Remarks
1
Export
Export
Export
Simultaneous export
capability of WR
High probability
2
Import
Export
Export
Import capability from NR
Low probability
(Load crash in NR)
3
Import
Import
Export
Export capability to SR
Low probability
4
Import
Import
Import
Simultaneous Import
capability of WR
5
Export
Import
Import
Export capability to NR
6
Export
Export
Import
Import capability from SR
Low probability
7
Export
Import
Export
Import capability from ER
High probability
8
Import
Export
Import
Export capability to ER
Low probability
Low/medium
probability
High probability (
Poor monsoon in
NR)
Based on above eight scenarios, TTCs on different corridors could be worked out
Real life vs reel life
N-1 criteria
“Element” in theory “Event” in
practice
45
(n-1)--Element or event ?
• Difference exists in n-1 criteria in planning and
operating horizon
– Tower collapse/lightning stroke on a D/C Tower.
– Two main one transfer scheme-Failure of opening of
400 kV Line breaker
• In practice-Results in multiple loss in elements
• As per planning criteria- not more than two elements should be
affected
– Coal fired station
• Fault in 132kV system- may result in loss of power supply to
CW system vis a vis tripping of multiple units
46
(n-1)--Element or event ? … contd
• Non availability/Outage/Non operation of Bus bar protection
– Results in tripping of all lines from remote stations
• Weather disturbance or floods
– Might result in loss of substation/multiple lines in the same corridor
• Breaker and a half scheme
– Outage of combination of breakers may result in tripping of multiple
line for a fault in one line
47
Regulatory initiatives
• Modifications in Grid Code & other regulations
– Frequency band tightening
– Cap on UI volume, Additional UI charge
– Inclusion of new definitions (TTC, ATC, Congestion)
• Congestion Charge Regulation
– Congestion Charge Value, Geographical discrimination
– Procedure for Assessment of Transfer Capability
– Procedure for Implementation of Congestion Charge
48
Suggestions for improving transfer capability-1
• installation of shunt capacitors in pockets prone to high reactive drawal
& low voltage
• strengthening of intra-state transmission and distribution system
• improving generation at load centre based generating stations by R&M
and better O & M practices
• avoiding prolonged outage of generation/transmission elements
• reduction in outage time of transmission system particularly those
owned by utilities where system availability norms are not available
Suggestions for improving transfer capability-2
• minimising outage of existing transmission system for
facilitating construction of new lines
• expediting commissioning of transmission system-planned
but delayed execution
• enhance transmission system reliability by stregthening of
protection system
• strengthening the safety net- Under voltage load shedding
schemes, system protection schemes
NR:
FLOWGATES
Central UP-Western UP
UP-Haryana/Punjab
WR:
Chandrapur-Padghe
Chandrapur-Parli
Bina-Gwalior
Soja-Zerda
SR:
Vijaywada-Nellore
Hossur-Selam
Cadappa-Kolar
Neyvelli-Sriperumbudur
ER:
Farakka-Malda
Malda-Purnea
Talcher-Rourkela
Jamshedpur-Rourkela
Farakka-Kahalgaon
Kolaghat-Baripada-Rengali
Part B
Ancillary Services in the Indian context
Definition………………(1)
• As per IEGC, 2010
“Ancillary services in power system (or grid) operation means
services necessary to support the power system (or grid)
operation in maintaining power quality, reliability and security of
the grid, e.g active power support for load following, reactive
power support, black start etc”
• The Appellate Tribunal for Electricity,
judgment in appeal no.202
“Ancillary services are those functions performed to support the
basic services of generation, transmission, energy supply and
power delivery. Ancillary services are required for the reliable
operation of the power system.”
Definitions………..……(2)
 “Ancillary services are those functions performed to support the
basic services of generation, transmission, energy supply and
power delivery. Ancillary services are required for the reliable
operation of the power system.”… Clause 30, order no.205 dated
13th December 2006, The Appellate Tribunal for Electricity
 “Ancillary services are those functions performed by the
equipment and people that generate, control, transmit, and
distribute electricity to support the basic services of generating
capacity, energy supply, and power delivery.”….Electric Power
Ancillary Service, Eric Hirst and Brendan Kirby
 “necessary to support the transmission of electric power from
seller to purchaser given the obligations of control areas and
transmitting utilities within those control areas to maintain
reliable operations of the interconnected transmission
system”….FERC
Drivers
• Reliability and Security
• Deregulated Power Systems
• Changing Nature of Electricity Grid
• Services to be obtained from Service Providers
• Cannot be coupled with basic energy services
• Use of UI surplus amount as per UI regulations – March
2009
Pillars of Market Design
Sally Hunt – ‘ Making Competition Work in Electricity’
Ancillary Services – International Experience
Categories of ancillary services
• Frequency Control Services
• Network control Services
• System Restart Services
Frequency Control Services
Governing system
Re-dispatch
AGC or LFC
Deployment times a key factor for categorizing
Frequency Control
Services (2)
Network control services
• Voltage Control services
– Primary…….(AVR)
– Secondary……..centralized automatic
– Tertiary………..Manual optimization
System restart services
• Black start capability of generating units
– Dead bus charging on request
– Ability to feed load
– Frequency control
– Voltage control
– Act on the directions of system operator
POSOCO’s Approach Paper
• Approach paper on ‘Ancillary Services in Indian
Context’ published by POSOCO in June’10
– Submitted to the Commission
– Comments sought from stakeholders
• Proposed services in the approach paper
– Load Generation Balancing Service (LGBS)
•
Use of un-despatched surplus, peaking and pumping stations
– Network Control Ancillary Service (NCAS)
•
•
Power Flow Control Ancillary Service (PFCAS)
Voltage Control Ancillary Service (VCAS)
–
use of synchronous condensers
– System Restart Ancillary Service (SRAS)
63
Petition on Ancillary Services
• Petition by NLDC
– 29th November 2010
• Service identified for immediate implementation
– Roadmap and mechanisms for introducing Frequency Support
Ancillary Service (FSAS)
• LGBS renamed as FSAS
• Harness un-despatched generation
– Liquid fuel based
– Diesel based
– Merchant/ IPPs/ CPPs
• Increase overall efficiency
• Maximization of generation at optimal cost
Implementing FSAS through Power Exchanges
• Facilitation of FSAS through Power Exchanges
– Direct/ trader procurement avoided
• New product for introducing FSAS
• Separate category of user group
– Seller registration for FSAS
• Part of the existing settlement mechanism including
deviations
• Proper telemetry
• Standing clearance from concerned
SLDC/RLDC
Procurement of FSAS
• Competitive Bidding Process
• After closure of DAM
– Sellers to bid in either exchange
– Declaration of supplier, bid area, quantum, duration
and price
• NLDC to compile and stack the bids
– For every hour of the next day
– Stacking based on bid price
• Transmission Charges and Losses applicable
Despatch of FSAS
• Despatch in real time
– System Conditions
– Anticipated Frequency profile
• Lower limit of IEGC band as threshold frequency
– Merit Order of bids
• Certainty of despatch for 12 time blocks
• Despatch in case of Congestion
– Merit order may be discounted
– TTC across seams to be honored
• Consent from seller
– Participants free to schedule in STOA
Scheduling of Bids
• Despatched bids directly incorporated in
schedule of sellers
• Unmatched one to one schedule
• Creation of a notional entity ‘POOL’
– For scheduling bids under FSAS
– Despatched bids attributed towards drawal of the
‘POOL’
• Drawees of despatched power to pay UI charges
• Scheduling as per present practice on regional
basis
Settlement of Bids
• Options for settlement
• Uniform pricing
• Pay as Bid Pricing
– Commission to decide
• Upper limit of CERC UI vector : ceiling price
– No commitment or penalty charge
• Payment to sellers through power exchanges
– UI pool of respective regions
– Transfer of Funds from regional UI pool to exchanges
– Payment made 30 days after the day of operation
• UI settlement takes approximately 4 weeks
• Power Exchanges to get facilitation Charges
• Deficit met through PSDF
Thank you
Discussion………