Transcript Index [www.srldc.org]

TTC/ATC Computations and Ancillary
Services
in the Indian context
1
Outline
•
Part A:
TTC/ATC computations
• Transfer capability-Definitions
• Relevance of transfer capability in Indian electricity market
• Difference between Transfer capability and Transmission
Capacity
• Assessment of TTC/TRM/ATC
• Method for improving Transfer capability
• Concerns
•
Part B:
Ancillary services in the Indian context
2
Part A
Total Transfer Capability (TTC)/
Available Transfer Capability (ATC)
computations
3
Transfer Capability Definitions
4
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.
• “Credible contingency” means the likely-to-happen
contingency, which would affect the Total Transfer
Capability of the inter-control area transmission system
– Outage of single transmission element (N-1) in the
transmission corridor or connected system whose
TTC is being determined
– Outage of the largest unit in the importing control area
7
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.
8
Non Simultaneous & Simultaneous transfer Capability
Non-simultaneous Transfer Capability
•
•
Amount of electric power that can be reliably transferred between two areas
of the interconnected electric system when other concurrent normal base
power transfers are held constant
Determined by simulating transfers from one area to another independently
and non-concurrently with other area transfers.
Simultaneous Transfer Capability
•
Is the amount of electric power that can be reliably transferred between two
or more areas of the interconnected electric system as a function of one or
more other power transfers concurrently in effect.”
•
Reflects simultaneous or multiple transfers with interdependency of
transfers among the other areas is taken into account.
•
No simple relationship exists between non-simultaneous and simultaneous
transfer capabilities
•
The simultaneous transfer capability MAY be lower than the sum of the
individual non-simultaneous transfer capabilities.
•
Simultaneous TTC declared by NR, SR, NER
•
Simutanous TTC can be declared for 2 regions combined also( e.g9
ER/NER)
Simultaneous TTC
Area A
Area C
2000 MW
4000 MW
Area B
5000 MW
10
TTC affected by transactions
11
Simultaenous TTC limits to two regions
Link
Time
TTC
ER-NR
ER-NR
ER-NER
ER-NER
PK
OFF-PK
PK
OFF-PK
2500
2500
400
400
Scheduling
Limit
2200
2200
350
350
•January’11 TTC figures
•N-1 contingency of 400KV FSTPP-Malda
•FSTPP-KHSTPP D/C limitation during outage of 400Kv Malda-Purnea D/C
•High voltages along Northern corridor
•As 400KV FSTPP-Malda serves both NR & ER in case of increase in TTC of ERNER ER-NR TTC has to be decreased
•Thus we could declare a simultaneous TTC of ER-NR & ER-NER combined12
Simultaneous TTC limits to two regions
INITIAL
REVISED
LINK
TIME
TTC
SCHEDUL TTC
ING LIMIT
SCHEDUL
ING LIMIT
ER-NR
PK
2800
2500
2700
2400
ER-NR
OFF-PK
2800
2500
2500
2200
ER-NER
PK
470
420
550
450
ER-NER
OFF-PK
470
420
550
450
•February,2011 limits
•NER TTC INCREASED DUE
REQUIREMENT OF NER(ASSAM)
TO
INCREASED
GOI
ALLOCATION
&
•NR TTC CORRESPONDINGLY DECREASED
13
Relevance of Transfer Capability
in
Indian Electricity Market
14
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.]
15
LT/MT/ Connectivity procedures-2010
ATC checking  MTOA approvals::
• CTU(nodal agency) shall notify TTC on 31st day of March of each year: for
4 (four) years
• Revision by CTU due to change in anticipated network topology or change
of anticipated generation or load at any of the nodes
• Available Transfer Capability (ATC) for MTOA will be worked out after
allowing the already approved applications for Long-term access, Medium
Term Open Access and Transmission reliability margin
• Grant of MTOA shall be subject to ATC
ATC checking  LTA approvals
• CTU(nodal agency) shall carry out system studies in ISTS to examine the
adequacy of the transmission system corresponding to the time frame of
commencement of long-term access to effect the desired transaction of
power on long-term basis, using the Available Transfer Capability (ATC).
• If transmission system augmentation is required LTA would be granted
subject to such augmentation
• Revision by CTU due to change in anticipated network topology or change
of anticipated generation or load at any of the nodes
16
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.
17
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.”
18
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
19
Reliability Margin
20
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.
21
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”
22
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”
23
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;
24
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
25
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
26
Difference between Transfer
Capability and Transmission
Capacity
27
Area Despatch- Example of TTC
Area A
Area B
515 MW
750 MW
630 MVA
515 MW
28
Transfer capability & Transmission
capacity – what’s the difference?
• Transfer capacity
– Refers to thermal ratings
• Transfer capability
– Refers to the system’s capability of transfer-varies considerably
with system conditions
– Can not be arithmetically added for the individual line capacities
and ratings
– Always less than the aggregated transmission interface between
two areas
1015 MW
750 MW
630 MVA
TTC = 630 MVA
29
TTC is directional
Area A
Area B
500 MW
Gen
1000 MW
1000 MW
Transfer Capability from
Area B to Area A = 500MW
500 MW
500 MW
Transfer Capability from Area
A to Area B = 1500MW
30
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
31
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 of connection of the customer and the quantum of demand
Other transactions through the area
Parallel flow in the network
• Transmission Capacity is independent of all of the above
• When electric power is transferred between two areas
the entire network responds to the transaction
32
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. 33
34
35
Assessment of
Transfer Capability
36
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
37
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)
38
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.
39
Operating Limits
Thermal Limit
• Maximum electrical current that a transmission line or electrical
facility can conduct over specified time periods before it sustains
permanent damage by overheating or before it violates public safety
requirements.
• Source CBIP Technical Report
Voltage limit
• To be maintained as per IEGC
• Minimum voltage limits can establish the maximum amount of
electric power that can be transferred without causing damage to the
electric system or customer facilities
• Widespread collapse of system voltage can result in a black out of
portions or the entire interconnected network
• Critical voltage for these nodes may also be different. Thus the
proximity of each node to the voltage collapse point may be
different(VCPI Index)
• 0 < VCPI < 1 0  stability 1  instability
• Voltage collapse  credible event
40
41
Operating Limits
Stability Limits
• property of a power system that enables it to remain in a state of operating
equilibrium under normal operating conditions and to regain an acceptable state of
equilibrium after being subjected to a disturbance(small or large)
• All generators connected to ac interconnected transmission system operate in
synchronism. Immediately following a system disturbance, generators begin to
oscillate relative to each other,causing fluctuations in system frequency, line
loadings, and system voltages.
• oscillations must diminish as the electric systems attain a new, stable operating
point.
• If stable point is not quickly established, the generators will likely lose synchronism
& result of generator instability may damage equipment and lead to widespread
loadsheddings
42
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
43
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
44
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 / CTU & STU data
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
Forecast by SLDCs/LGBR of RPCs/past trend/Anticipated
9
Credible contingencies
Planning criteria + Operator experience
45
Model to be considered for simulation studies
•
•
•
•
•
•
•
•
•
•
Assumption of standard data from CEA manual on Transmission
planning criteria
Separate base cases for calculating the export and import capability
corresponding to both peak and off- peak load and generation with the
likely scenario
Wind generation also needs to be modelled  forecasts
Reactive capability of units  Actual generator capability curve / CEA
manual in Transmission planning
Nodal MW demand  forecast by SLDCs/LGBR of RPCs/past trend
Nodal MVAR demand  SLDC forecast OR CEA Planning criteria :
Normal operating limits for transmission line: CEA planning criteria
(detailed calculation methodology  )
Emergency limit for transmission line  110% of normal operating limit
Continuous Operating limit for ICTs  generally 90% of MCR
Reasonable assumptions in case data NA
46
Data preparation for LF studies
•
•
Where actual system is not available data from CEA Manual on
transmission planning criteria can be used w.r.t parameters as:
– Load Power factor
0.85 lag – peak
0.90 lag – Off-peak OR
0.75 lag-peak
0.85 lag – off-peak [Agricultural]
– Reactive limits
Qmax = 0.5* Active generation
Qmin = -0.5 *Qmax
– transformer/ reactance – 14-15%
– GT – 12.5%
Where actual system data is not available:
– Standard R, X, B parameters(p.u/km/ckt) at 100MVA base may be used
– Other typical system data may be used
47
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
48
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
49
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(St.Clair’s curve)
 K3
 Permissible line loading = SIL X k1 x k2 x 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
50
St.Clair’s curve
Line loading in terms of SIL of an uncompensated line as a function of Length
assuming voltage regulation of 5% and 30 deg angular difference
51
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
52
Min of PL and Pth_summer
5
6
7
8
Illustration of
calculation of
operating limits
of transmission
line
52
TTC/ATC calculation methodology-As per
congestion charge procedures
• Total Transfer Capability between two areas would be assessed by
increasing the load in the importing area and increasing the generation
in the exporting area or vice versa till the constraints are hit for a
credible contingency
Credible contingencies
• Outage of single transmission element (N-1) in the transmission
corridor or connected system whose TTC is being determined as
defined in IEGC
• Outage of a largest unit in the importing control area Station.
TTC is limited by::
• Violation of grid voltage operating range OR
• Violation of transmission element operating limit in the base case OR
• Violation of emergency limit in the contingency case
53
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
54
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
55
TTC calculation process
Considerations for calculation of TRM – as per congestion procedures
•Two percent (2%) of the total anticipated peak demand met in MW of the control
area/group of control area/region (to account for forecasting uncertainties)
•Size of largest generating unit in the control area/ group of control area/region
•Single largest anticipated in feed into the control area/ group of control area
Data flow TTC calculation
SLDC  RLDC  Import/Export TTC of control areas
NLDC  RLDC  Fixation of inter-regional export
RLDC  NLDC  Preparation of converged base case
NLDC  RLDC  Stitching of base cases from all regions & re-consideration
for modification if any
RLDC  NLDC  Final Base Case
NLDC  Final TTCs uploaded to NLDC wesbite & linked from RLDC
websites(upto 3 months advance)
•NLDC can revise the TTC/ATCs on requests by RLDCs/SLDCs/suo-motto
•The TTC/RM/LTA/approved STOA(till date) & path margin available are declared
alongwith the rationale/path limiting the TTC
56
Procedure for declaration of TTC,
TRM, ATC and anticipated Constraints
• Role of SLDC
• Assess the TTC, TRM and ATC on its
inter-State
transmission
corridor,
considering its own control area
• Indicate details of anticipated transmission
constraints in the intra State system
• Forward these figures along with the
assumptions made, to the respective
RLDC, for assessment of TTC at the
regional level
57
Procedure for declaration of TTC,
TRM, ATC and anticipated Constraints
• Role of RLDCs
• Consider the inputs provided by SLDCs
• Assess TTC, TRM and ATC for
–
–
–
–
intra regional corridors (group of control
areas)
individual control areas within the region (if required)
Inter-regional corridors at respective ends
for a period of three months in advance.
• Forward the results along with the input data
considered, to NLDC
• Also indicate the anticipated constraints in the
intra-regional transmission system
58
Procedure for declaration of TTC, TRM,
ATC and anticipated Constraints
• Role of NLDC
• Assess the TTC, TRM and ATC of inter and
intra-regional links/ Corridors respectively
for three months in advance based on
– The inputs received from RLDCs
– TTC/ TRM/ ATC notified/ considered by CTU for
medium-term open access.
• Inform the TTC/ TRM/ ATC figures along
with constraints observed in inter-regional/
intra-regional corridors to the RLDCs
59
Procedure for declaration of TTC, TRM,
ATC and anticipated Constraints
• Role of NLDC (contd)
• Revise the TTC, TRM and ATC due to
change in system conditions (including
commissioning of new transmission lines/
generation), vis-à-vis earlier anticipated
system conditions
• Revise TTC, TRM and, ATC based on its
own observations or based on inputs
received from SLDCs/ RLDCs
60
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
61
Sample TTC uploaded at NLDC website
62
63
64
4
NORTHERN
REGION
2
NORTHEASTERN
REGION
WESTERN
REGION
8
16
EASTERN
REGION
4
SOUTHERN
REGION
65
Possible scenarios for a control area with N
interconnections
n
• Total No. of scenarios possible = 2
• ER  4 inter-regional interconnections  16 possible
scenarios
• WR 3 inter-regional interconnections  8 possible
scenarios
• Out of above only limited No. of scenarios applicable
• For ER only 3 to 4 out of 16 scenarios possible
• Different
scenarios
dependent
upon
seasonal
characteristics due to the nature of skewed geo-spatial
positioning of hydro/Thermal Generators in ER
• From the analysis below we see that simultaneous
export/import capability calculation is not possible for ER
66
Possible scenarios for Eastern Regional Grid
Sl.NO.
NR
WR
SR
NER
Remarks
1
Exp
Exp
Exp
Exp
Simultaenous Export capability.
Probability extremely low
2
Exp
Exp
Exp
Imp
Probability very low
3
Exp
Exp
Imp
Exp
Probability very low
4
Exp
Exp
Imp
Imp
Probability low. Only in high
hydro season & high demand in
WR/NR
5
Exp
Imp
Exp
Exp
Probable in winter load / low
hydro conditions
6
Exp
Imp
Exp
Imp
lesser Probability
7
Exp
Imp
Imp
Exp
Probability low
8
Exp
Imp
Imp
Imp
Probable in high hydro season
67
Possible scenarios for Eastern Regional Grid
Sl.NO.
NR
WR
SR
NER
Remarks
9
Imp
Exp
Exp
Exp
Very low probability-Temporarily
possible only in case of demand
crash/trippings in NR
10
Imp
Exp
Exp
Imp
Very low probability
11
Imp
Exp
Imp
Exp
Very low probability
12
Imp
Exp
Imp
Imp
Very low probability
13
Imp
Imp
Exp
Exp
low probability-in case of
demand crash/trippings in NR
14
Imp
Imp
Exp
Imp
very low probability
15
Imp
Imp
Imp
Exp
Very low probability
16
Imp
Imp
Imp
Imp
Simultaenous import cabaility
Probability extremely low
68
N-1 criteria
“Element” in theory “Event” in
practice
In real time a Single event can
lead to multiple outages
69
(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
70
(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
71
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
Farakka-Kahalgaon
Kolaghat-Baripada-Rengali 72
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
73
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 strengthening of
protection system
• strengthening the safety net:
 UFLS,
 UVLS,
 SPS
74
Part B
Ancillary Services in the Indian context
75
Outline
• Definition of ancillary services
• Categories of ancillary services
• Ancillary services in the Indian context
76
Ancillary services……definitions
•
Those services that are necessary to support the transmission of capacity and
energy from resources to loads while maintaining reliable operation of the
Transmission Service Provider's transmission system in accordance with good
utility practice. (From FERC order 888-A.)
•
“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.”… Para
30, judgment in appeal no.202 dated 13th December 2006, The Appellate
Tribunal for Electricity[4]
•
“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[5]
77
Ancillary services……definitions (2)
• “Ancillary Services” means in relation to power
system (or grid) operation, the services necessary
to support the power system (or grid) operation in
maintaining power quality, reliability and security of
the grid, eg. active power support for load following,
reactive
power
support,
black
start,
etc;………………….Indian Electricity Grid Code 2010
Approach Paper on Ancillary Services submitted to CERC in June 2010
by National Load Despatch Centre (NLDC)
78
Relevance of ancillary services
Four pillars of market structure
79
Categories of ancillary services
• Frequency Control Services
• Network control Services
• System Restart Services
80
Levels of frequency control
Primary frequency response
•Immediate response by  adjustment of active power of generating units
& consumption of controllable loads to check the deviation in frequency
– speed governor (having droop settings)-FGMO/RGMO
– self-regulating effect of frequency-sensitive loads (e.g.induction
motors)or the action of frequency-sensitive relays
Secondary frequency response
•Centralized automatic control that adjusts the active power production of
the generating units to restore the frequency and the interchanges with
other systems to their target values following an imbalance by:
– setpoint or reference point adjustment of generators,
– starting and stopping of power plants
•Goal of secondary frequency control is to minimize the area control error
(ACE) [ACE is the instantaneous difference between net actual and
scheduled interchange, taking into account the effects of frequency bias]
•Absent by design in India
81
•In US/UK known as AGC / LFC
Levels of frequency control
Tertiary frequency rseponse
•Manual changes in the despatching and commitment of generating
units
•Used to restore the primary and secondary frequency control reserves,
to manage congestions in the transmission network, and to bring the
frequency and the interchanges back to their target value in case
secondary control is unable
•India  Manual load shedding / ABT mechanism
82
Frequency Control Services
Governing system
Re-dispatch
AGC or LFC
Deployment times a key factor for categorizing
83
Frequency Reserves
Spinning/Reliability reserves
•Fast acting units/ controllable loads capable of instantaneous
response
•Cannot support for long durations
•Can be provided by synchronized Hydro units/DG sets having reserve
margins
Supplementary reserves
•Response time not as quick as spinning reserves
•Capable of operating at increased power output for longer duration
•Manual intervention for activation
•Can be provided by units on hot standby
Backup reserves
•Can stay in service for a longer time
•Response time higher e.g. > 30mins
84
Generating
unit
-levels of
control
85
Voltage Control
Primary voltage control
•Local automatic control that maintains the voltage at a set point vide
AVR of generator
•Devices as static voltage compensators(SVC), can also participate
Secondary voltage control
•Is a centralized automatic control that coordinates the actions of local
regulators in order to manage the injection of reactive power within a
regional power system.
Tertiary voltage control
•Refers to the manual optimization of reactive power flows by say:
– Switching in/out shunt/series compensations
– Opening of lines to control overvoltage,etc
– Asking generators to operate in lead/lag mode
– Using other dynamic/static reactive compensating equipments
•IEGC mandates charging VAR exchanges with ISTS beyond the
range 97% to 103%
86
Drivers for Ancillary Services
• Reliability and Security
• Deregulated Power Systems
• Services to be obtained from Service Providers
• Decoupling with basic energy services
• Regulatory Directives:
– NLDC/RLDCs to identify ancillary services as per clause 11.1 of
the amended CERC UI Regulations, 2009
““ b. Providing ancillary services including but not limited to ‘load
generation balancing’ during low grid frequency as identified by the
Regional Load Despatch Centre, in accordance with the
procedure prepared by it, to ensure grid security and safety:”
87
Ancillary services-comparison with international markets
88
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)
89
POSOCO’s Approach Paper
• Comments received from various stakeholders
• Service identified for immediate implementation
– Frequency Support Ancillary Service (FSAS)
•
LGBS renamed as FSAS
– Other services identified to be introduced
subsequently, as the market matures
• Petition filed by NLDC
– proposing roadmap and mechanism for introducing
FSAS
90
Frequency Support Ancillary Service
(FSAS)
• Focus on utilizing idle generation
– High liquid fuel and diesel cost
– Fragmented need of load serving entities/buyers
– Concern with frequent start stop operation
• Utilization of un-despatched generation from
– Liquid fuel based
– Diesel based
– Merchant/ IPPs/ CPPs
• Quantum available under this service could be limited
– frequency may not always be contained in the operation band
• Proposed amendments for introduction of separate peak tariff would
compliment with monetary recovery / incentives
91
Implementation of FSAS
• Facilitation through Power Exchange
– Separate category of user group
– Standing clearance from SLDC/RLDC
– Bids to be invited after closure of DAM
– Supplier, bid area, quantum, duration and price to be specified
– NLDC to compile bids as per bid price, area
– Transmission charges/losses as applicable for collective
transactions would be applicable
• Despatch of bids under FSAS
– System Operator to dispatch based on anticipated deficit and
frequency profile
– Threshold frequency: lower limit in the IEGC band
– Dispatch certainty of at least 12 time blocks
– Merit order to be ensured: low cost bids dispatched first
92
Implementation of FSAS
• Dispatch in case of congestion
– ATC limits to be honored
– Merit order discounted in case of congestion
– Lower price bids may be skipped
– Downstream bids dispatched first
• Scheduling of bids under FSAS
– Directly incorporated in the schedule of sellers
– No matching one-to-one drawal schedule
– Attributed towards drawal of a fictitious entity i.e ‘POOL’
–
–
–
buyer/ drawee entity to pay back in the form of UI charges
Difference expected to be +ve in low frequency & -ve in case of high
frequency
Frequency can deviate despite service triggering due to limited quantum
• Consent from sellers before dispatch
– To ascertain readiness for dispatch
– Agreed quantum scheduled after 6 time blocks
– UI liability in case of failure to honour commitment
93
Implementation of FSAS
• Options for settlement
– ‘Pay-as-bid price’
– ‘Uniform Pricing’  All bids dispatched uniformly @ price of
highest accepted bid
– To be finalized by the Commission
• Ceiling price for despatch of bids
– CERC’s UI vector ceiling price
• Payment settlement through power exchange
• Settlement on post-facto basis
– On (n+1)th day or next working day
• Amount equivalent to FSAS bids dispatched in a region at the
respective bid price would be transferred from regional UI pool to
Power Exchanges
• Deficit if any to be funded from the PSDF via the Ancillary services
fund
• Power exchanges to be paid facilitation charges
94
Ancillary Services Fund
• ‘Ancillary Services Fund’ account to be opened and
maintained by NLDC
• Procurement of Ancillary Services
– Funded from the PSDF via Ancillary Services Fund
– Clause 4 of CERC’s PSDF Regulation
– Clause 11 of CERC’s amended UI Regulations
95
Ancillary services-further scope
Pumped storage plants
• Reimbursement of loss amount corresponding to power consumed
and generated on UI discounted by efficiency factor
Network Control ancillary services(NCAS)
• Power flow control ancillary services(PFCAS)
– Settlement similar to FSAS
• Voltage control ancillary services
– Operation of synchronous machines in synchronous condenser mode – initially
hydro but could be possible for Gas & old Thermal stations in future
– Reimbursement of charges on paise/KVARH basis discounting voltage factor
– Power consumed due to windage/friction losses & resulting UI to be nullified and
socilized in the pooled losses
– Mobile reactive installations
System restart ancillary services(SRAS)
• Incnetivization for successful mock black starts
96
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
97
Ancillary services-Into the future
Primary frequency control
• Frequency responsive demand disconnection by Bulk consumers
Spinning reserves
• Contracted hydro / demand disconnection
• Frequency responsive automated initiation
Reactive ancillary market
• Separation of FC in terms of utilization to produce real & reactive
power
• Bid based procurement of reactive power
Reatime reactive market
Procurement of Dynamic Vars-voltage stability & enhancement of
98
Transfer capability
Thank you
99