ttc/atc computations and ancillary services in the indian context

1

TTC/ATC Computations and Ancillary

Services

in the Indian context

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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”

6

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”

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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

ER-NR

•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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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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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

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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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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”

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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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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

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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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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)

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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.

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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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Operating LimitsStability 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

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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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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

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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

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Ampacity

Conductor Type

Ampacity

More than 10 years of age

65 degree conductor 75 degree conductor

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

For bundled conductors

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

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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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Permissible Line Loading LimitsFrom 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

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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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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

5 Conductor typeACSR Twin

Moose

75o C design conductor temperature and age >10

years

6 Line reactance (X) 0.0002075 Per unit / kilometer / circuit

7 Line susceptance (B) 0.0055 Per unit / kilometer / circuit

8 Base MVA 100

9Power transfer between adjacent buses at 5 % voltage

regulation and 30 deg angular separation = PB593 (in MW)

10 Total shunt compensation for the line in MVAr 145 Sl. No. (2) + (3)

11 Line charging MVAr 212Line 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 Min of PL and Pth_summer

Illustration of calculation of

operating limits of transmission

line

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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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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

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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


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• 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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• 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

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Sample TTC uploaded at NLDC website

65

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

75

Part B

Ancillary Services in the Indian context

76

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

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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

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Frequency Control Services

Deployment times a key factor for categorizing

Governing system

AGC or LFC

Re-dispatch

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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

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Generating unit-levels of control

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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%

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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:”

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Ancillary services-comparison with international markets

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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)

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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

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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

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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

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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

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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