ttc/atc computations and ancillary services in the indian context
DESCRIPTION
TTC/ATC Computations and Ancillary Services in the Indian context. 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 - PowerPoint PPT PresentationTRANSCRIPT
1
TTC/ATC Computations and Ancillary
Services
in the Indian context
2
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
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Part A
Total Transfer Capability (TTC)/ Available Transfer Capability (ATC)
computations
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Transfer Capability - Definitions
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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”
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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
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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.
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Non Simultaneous & Simultaneous transfer CapabilityNon-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.g ER/NER)
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Simultaneous TTC
Area A Area B
Area C
2000 MW 4000 MW
5000 MW
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TTC affected by transactions
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Simultaenous TTC limits to two regions
Link Time TTC Scheduling
Limit
ER-NR PK 2500 2200
ER-NR OFF-PK 2500 2200
ER-NER PK 400 350
ER-NER OFF-PK 400 350
•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 ER-NER ER-NR TTC has to be decreased
•Thus we could declare a simultaneous TTC of ER-NR & ER-NER combined
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ER-NR
•February,2011 limits
•NER TTC INCREASED DUE TO INCREASED GOI ALLOCATION & REQUIREMENT OF NER(ASSAM)
•NR TTC CORRESPONDINGLY DECREASED
INITIAL REVISED
LINK TIME TTC SCHEDULING LIMIT
TTC SCHEDULING 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
Simultaneous TTC limits to two regions
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•June, 2011 limits
•ER TTC REDUCED DUE TO LOW VOLTAGE IN CHENNAI AREA & HIGH LOADING ON 400 KV VIJAYAWADA – NELLORE I & II.
INITIAL (Sep-10) REVISED (Jun-11)
LINK TIME TTC SCHEDULING LIMIT
TTC SCHEDULING LIMIT
ER-SR PK 2650 2600 1900 1900
ER-SR OFF-PK 2950 2900 2000 2000
WR-SR PK & OFF-PK
1000 1000 1000 1000
Simultaneous TTC limits to two regions
•July, 2011 limits
•WR TTC REDUCED TO 800 MW DUE TO COMMISSIONING OF SIMHADRI U # 3.
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Relevance of Transfer Capability in
Indian Electricity Market
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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.]
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LT/MT/ Connectivity procedures-2010ATC 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
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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.
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Open Access Theory & PracticeForum 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.”
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Reliability Margin
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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.
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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”
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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;
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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
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Difference between Transfer Capability and Transmission
Capacity
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Area Despatch- Example of TTC
750 MW
630 MVA
515 MW
Area AArea B
515 MW
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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
750 MW
630 MVA
1015 MW
TTC = 630 MVA
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TTC is directional
500 MW
Area AArea B
500 MW1000 MW
1000 MW
Gen
500 MW
Transfer Capability from Area A to Area B = 1500MW
Transfer Capability from Area B to Area A = 500MW
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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
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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
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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.
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Assessment of Transfer Capability
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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
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Operating LimitsThermal 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
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Total Transfer Capability: TTC
Voltage Limit
Thermal Limit
Stability Limit
Total Transfer Capability
Total Transfer Capability is the minimum of the Thermal Limit, Voltage Limit and the Stability Limit
Time
Power Flow
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Intra-day STOA
Day-ahead STOA
Collective (PX) STOA
First Come First Served STOA
Advance Short Term Open Access (STOA)
Medium Term Open Access (MTOA)
Long Term Access (LTA)
Reliability Margin (RM)
Available Transfer Capability is
Total Transfer Capability less Reliability Margin
TTC ATC
RM
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Input Data and SourceS 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
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Thermal limit derived from ampacity
Conductor Type
Thermal limit in MW at 0.975 pu voltage and unity p.f.
More than 10 years of age
65 degree conductor 75 degree conductor
40o ambient 10o ambient
40o 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
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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
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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
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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
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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
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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
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• 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
Procedure for declaration of TTC, TRM, ATC and anticipated Constraints
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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
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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
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Transfer Capability assessment
AnticipatedNetwork topology +Capacity additions
Anticipated Substation Load
Anticipated Ex bus
Thermal Generation
Anticipated Ex busHydro generation
LGBR
Last Year
Reports
WeatherForecast
Trans.Plan +
approv.S/D
Last Year
patternOperator
experience
Planning criteria
Operating limits
Credible contingencies
Simulation
Analysis
Brainstorming
Total Transfer Capability
ReliabilityMargin
less
AvailableTransfer
Capability
equals
Planning Criteria is strictly followed during simulations
63
Sample TTC uploaded at NLDC website
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65
66
EASTERN REGION
SOUTHERN REGION
WESTERNREGION
NORTHERN REGION
NORTH-EASTERN REGION
2
8
4
16
4
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Possible scenarios for a control area with N interconnections
• Total No. of scenarios possible = 2n
• 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
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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
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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
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N-1 criteria“Element” in theory “Event” in
practice
In real time a Single event can lead to multiple outages
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(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
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• 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
(n-1)--Element or event ? … contd
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FLOWGATES
NR:
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
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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
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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
76
Part B
Ancillary Services in the Indian context
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Outline
• Definition of ancillary services
• Categories of ancillary services
• Ancillary services in the Indian context
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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]
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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)
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Relevance of ancillary servicesFour pillars of market structure
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Categories of ancillary services
• Frequency Control Services
• Network control Services
• System Restart Services
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Levels of frequency controlPrimary 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
•In US/UK known as AGC / LFC
83
Levels of frequency controlTertiary 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
84
Frequency Control Services
Deployment times a key factor for categorizing
Governing system
AGC or LFC
Re-dispatch
85
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
86
Generating unit-levels of control
87
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%
88
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:”
90
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)
91
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
92
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
93
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
94
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
95
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
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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
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Ancillary services-further scopePumped 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
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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
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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 Transfer capability
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Thank you