TTC/ATC Computations

and

Ancillary Services

in the Indian context

ByNational Load Despatch Centre

PSTI Bengaluru10th August 2011

Outline

• Part A: TTC/ATC computations

• Transfer Capability - Definition• Relevance of transfer capability in Indian electricity market• Difference between Transfer capability and Transmission

Capacity• Assessment of Transfer Capability• Ratio of transfer capability to transmission capacity• Congestion

• Part B: Ancillary services in the Indian context

Part A

Total Transfer Capability (TTC)/ Available Transfer Capability (ATC)

computations

Transfer Capability - Definitions

North American Electric Reliability Corporation’s (NERC) definition of TTC

• The amount of electric power that can be moved or transferred reliably from one area to another area of the interconnected transmission systems by way of all transmission lines (or paths) between those areas under specified system conditions……….16-Mar-2007(FERC)

• As per 1995 document of NERC, following conditions need to be satisfied:– all facility loadings in pre-contingency are within normal ratings and

all voltages are within normal limits

– systems stable and capable of absorbing the dynamic power swings

– before any post-contingency operator-initiated system adjustments are implemented, all transmission facility loadings are within emergency ratings and all voltages are within emergency limits”

5

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”

Total Transfer Capability as defined in the IEGC and Congestion charge Regulations

• “Total Transfer Capability (TTC)” means the amount of electric power that can be transferred reliably over the inter-control area transmission system under a given set of operating conditions considering the effect of occurrence of the worst credible contingency.

Available Transfer Capability as defined in the IEGC and Congestion charge regulations

• “Available Transfer Capability (ATC)” means the transfer capability of the inter-control area transmission system available for scheduling commercial transactions (through long term access, medium term open access and short term open access) in a specific direction, taking into account the network security. Mathematically ATC is the Total Transfer Capability less Transmission Reliability Margin.

9

Simultaneous TTC

Area A Area B

Area C

2000 MW 4000 MW

5000 MW

Relevance of Transfer Capability in

Indian Electricity Market

Open Access in Inter-state Transmission Regulations, 2008

• 3( 2) The short-term open access allowed after long / medium term by virtue of-– (a) inherent design margins;– (b) margins available due to variation in power flows;

and– (c) Margins available due to in-built spare

transmission capacity created to cater to future load growth or generation addition.]

Tariff Policy Jan 2006

7.3 Other issues in transmission

(2) All available information should be shared with the intending users by the CTU/STU and the load dispatch centres, particularly information on available transmission capacity and load flow studies.

Open Access Theory & 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.”

13

Declaration of Security Limits

• “In order to prevent the violation of security limits, System Operator SO must define the limits on commercially available transfer capacity between zones.” CIGRE_WG_5.04_TB_301

• “System Operators try to avoid such unforeseen congestion by carefully assessing the commercially available capacities and reliability margins.” CIGRE_WG_5.04_TB_301

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Reliability Margin

16

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.

17

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”

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

Difference between Transfer Capability and Transmission

Capacity

Transmission Capacity Vis-à-vis Transfer Capability

Transmission Capacity Transfer Capability

1 Declared by designer/ manufacturer Declared by the Grid Operator

2 Is a physical property in isolation Is a collective behaviour of a system

3 Depends on design only Depends on design, topology, system conditions, accuracy of assumptions

4 Deterministic Probabilistic

5 Constant under a set of conditions Always varying

6 Time independent Time dependent

7 Non-directional (Scalar) Directional (Vector)

8 Determined directly by design Estimated indirectly using simulation models

9 Independent of Parallel flow Dependent on flow on the parallel path

Transfer Capability is less than transmission capacity because

• Power flow is determined by location of injection, drawal and the impedance between them

• Transfer Capability is dependent on– Network topology– Location of generator and its dispatch– Pont if connection of the customer and the quantum of demand – Other transactions through the area– Parallel flow in the network

• Transmission Capacity independent on all of the above

• When electric power is transferred between two areas the entire network responds to the transaction

77% of electric power transfers from

Area A to Area F will flow on the transmission path

between Area A & Area C

Assume that in the initial condition, the power flow from

Area A to Area C is 160 MW on account of a generation dispatch

and the location of customer demand on the modeled

network.

When a 500 MW transfer is scheduled from Area A to Area

F, an additional 385 MW (77% of

500 MW) flows on the transmission path from

Area A to Area C, resulting in a 545 MW power flow from

Area A to Area C.

Assessment of Transfer Capability

Transfer Capability Calculations must

• Give a reasonable and dependable indication of transfer capabilities,

• Recognize time variant conditions, simultaneous transfers, and parallel flows

• Recognize the dependence on points of injection/extraction

• Reflect regional coordination to include the interconnected network.

• Conform to reliability criteria and guides.

• Accommodate reasonable uncertainties in system conditions and provide flexibility.

27

Courtesy: Transmission Transfer Capability Task Force, "Available Transfer Capability Definitions and Determination", North American Electric Reliability Council, Princeton, New Jersey, June 1996 NERC

Europe• Increase generation in one area and lower it in the other.

• A part of cross border capacity is withdrawn from the market to account for– Random threats to the security of the grid, such as loss of a

generating unit. This capacity is called as Transmission Reliability Margin (TRM)

– TRM based on the size of the biggest unit in the synchronous area and the domestic generation peak of a control area.

• Net Transfer Capacity = TTC – TRM– published twice a year (winter and summer)

United States

• The commercial capacity available for market players is calculated by deducting Transmission Reliability Margin (TRM) and Capacity Benefit Margin (CBM) from Total Transfer Capability – TRM is set aside to ensure secure operation of the

interconnected transmission network to accommodate uncertainties in system operations while CBM is set aside to ensure access to generation from interconnected systems to meet generation reliability requirements.

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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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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 32

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

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 Limits

From Sec 4.1 of Transmission Planning Criteria• SIL at certain voltage levels modified to account for Shunt compensation

k1 = sqrt (1- degree of shunt compensation) Series compensation

k2 = 1 / [sqrt (1-degree of series compensation) Variation in line loadability with line length

K3

From Sec 4.2 of Transmission Planning Criteria• Thermal loading limits at conductor temperature of 75o • Ambient 40o in summer and 10o in winter

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

36

37

Steady State Voltage Limits

Voltage (kV rms)

Nominal Maximum Minimum

765 800 728

400 420 380

220 245 198

132 145 122

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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

Input Data and Source

39

S No. Input Data Suggested Source

1 Planning Criteria Manual on Transmission Planning Criteria issued by CEA

2 Network Topology Existing network with full elements available

Planned outages during the entire assessment period

New transmission elements expected

3 Transmission line limits Minimum of thermal limit, stability limit and voltage limit

4 Thermal unit availability Load Generation Balance report, Maintenance schedule

Anticipated new generating units

5 Thermal despatch Ex bus after deducting the normative auxiliary consumption

Output could be further discounted by the performance index of generating units of a particular size as compiled by CEA

6 Gas based thermal despatch

Past trend

7 Hydro despatch Peak and off peak actual hydro generation on median consumption day of same month last year

The current inflow pattern to be duly accounted

8 Load Anticipated load

9 Credible contingencies Planning criteria + Operator experience

Process for assessment

• Base case construction (The biggest challenge) – Anticipated network representation– Anticipated load generation– Anticipated trades

• Simulations– Increase generation in exporting area with

corresponding decrease in importing area till network constraint observed

40

EASTERN REGION

SOUTHERN REGION

WESTERNREGION

NORTHERN REGION

NORTH-EASTERN REGION

2

8

4

16

4

Case 1

WR GridNR

ER

SR Case 2

Case 3

NR

SR

ER

NR

ER

SR

Case4 NR

SR

ER

Case 5

WR GridNR

ER

SR Case 6

Case 7

NR

SR

ER

NR

SR

Case 8

NR

ER

Possible scenarios for Western Regional Grid

Sl.NO. NR ER SR Work out from this case Remarks

1 Export Export Export Simultaneous export capability of WR High probability

2 Import Export Export Import capability from NR Low probability (Load crash in NR)

3 Import Import Export Export capability to SR Low probability

4 Import Import Import Simultaneous Import capability of WR

Low/medium probability

5 Export Import Import Export capability to NR High probability ( Poor monsoon in NR)

6 Export Export Import Import capability from SR Low probability

7 Export Import Export Import capability from ER High probability

8 Import Export Import Export capability to ER Low probability

Based on above eight scenarios, TTCs on different corridors could be worked out

Real life vs reel life

N-1 criteria“Element” in theory “Event” in

practice

45

46

(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

Regulatory initiatives

• Modifications in Grid Code & other regulations – Frequency band tightening – Cap on UI volume, Additional UI charge– Inclusion of new definitions (TTC, ATC, Congestion)

• Congestion Charge Regulation– Congestion Charge Value, Geographical discrimination – Procedure for Assessment of Transfer Capability– Procedure for Implementation of Congestion Charge

48

Suggestions for improving transfer capability-1

• installation of shunt capacitors in pockets prone to high reactive drawal & low voltage

• strengthening of intra-state transmission and distribution system

• improving generation at load centre based generating stations by R&M and better O & M practices

• avoiding prolonged outage of generation/transmission elements

• reduction in outage time of transmission system particularly those owned by utilities where system availability norms are not available

Suggestions for improving transfer capability-2

• minimising outage of existing transmission system for facilitating construction of new lines

• expediting commissioning of transmission system-planned but delayed execution

• enhance transmission system reliability by stregthening of protection system

• strengthening the safety net- Under voltage load shedding schemes, system protection schemes

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

Jamshedpur-Rourkela

Farakka-Kahalgaon

Kolaghat-Baripada-Rengali

Part B

Ancillary Services in the Indian context

Definition………………(1)• As per IEGC, 2010 “Ancillary services in power system (or grid) operation means

services necessary to support the power system (or grid) operation in maintaining power quality, reliability and security of the grid, e.g active power support for load following, reactive power support, black start etc”

• The Appellate Tribunal for Electricity, judgment in appeal no.202

“Ancillary services are those functions performed to support the basic services of generation, transmission, energy supply and power delivery. Ancillary services are required for the reliable operation of the power system.”

Definitions………..……(2)

“Ancillary services are those functions performed to support the basic services of generation, transmission, energy supply and power delivery. Ancillary services are required for the reliable operation of the power system.”… Clause 30, order no.205 dated 13th December 2006, The Appellate Tribunal for Electricity

“Ancillary services are those functions performed by the equipment and people that generate, control, transmit, and distribute electricity to support the basic services of generating capacity, energy supply, and power delivery.”….Electric Power Ancillary Service, Eric Hirst and Brendan Kirby

“necessary to support the transmission of electric power from seller to purchaser given the obligations of control areas and transmitting utilities within those control areas to maintain reliable operations of the interconnected transmission system”….FERC

Drivers• Reliability and Security

• Deregulated Power Systems

• Changing Nature of Electricity Grid

• Services to be obtained from Service Providers

• Cannot be coupled with basic energy services

• Use of UI surplus amount as per UI regulations – March 2009

Pillars of Market Design

Sally Hunt – ‘ Making Competition Work in Electricity’

Ancillary Services – International Experience

Categories of ancillary services

• Frequency Control Services

• Network control Services

• System Restart Services

Frequency Control Services

Deployment times a key factor for categorizing

Governing system

AGC or LFC

Re-dispatch

Frequency Control Services (2)

Network control services

• Voltage Control services– Primary…….(AVR)– Secondary……..centralized automatic– Tertiary………..Manual optimization

System restart services

• Black start capability of generating units– Dead bus charging on request– Ability to feed load – Frequency control– Voltage control– Act on the directions of system operator

POSOCO’s Approach Paper

• Approach paper on ‘Ancillary Services in Indian Context’ published by POSOCO in June’10– Submitted to the Commission– Comments sought from stakeholders

• Proposed services in the approach paper– Load Generation Balancing Service (LGBS)

• Use of un-despatched surplus, peaking and pumping stations

– Network Control Ancillary Service (NCAS)• Power Flow Control Ancillary Service (PFCAS)

• Voltage Control Ancillary Service (VCAS)– use of synchronous condensers

– System Restart Ancillary Service (SRAS)

63

Petition on Ancillary Services• Petition by NLDC

– 29th November 2010

• Service identified for immediate implementation– Roadmap and mechanisms for introducing Frequency Support

Ancillary Service (FSAS)

• LGBS renamed as FSAS

• Harness un-despatched generation– Liquid fuel based

– Diesel based

– Merchant/ IPPs/ CPPs

• Increase overall efficiency

• Maximization of generation at optimal cost

Implementing FSAS through Power Exchanges

• Facilitation of FSAS through Power Exchanges– Direct/ trader procurement avoided

• New product for introducing FSAS• Separate category of user group

– Seller registration for FSAS• Part of the existing settlement mechanism including

deviations• Proper telemetry

• Standing clearance from concerned SLDC/RLDC

Procurement of FSAS

• Competitive Bidding Process

• After closure of DAM– Sellers to bid in either exchange– Declaration of supplier, bid area, quantum, duration

and price

• NLDC to compile and stack the bids– For every hour of the next day– Stacking based on bid price

• Transmission Charges and Losses applicable

Despatch of FSAS• Despatch in real time

– System Conditions– Anticipated Frequency profile

• Lower limit of IEGC band as threshold frequency

– Merit Order of bids

• Certainty of despatch for 12 time blocks• Despatch in case of Congestion

– Merit order may be discounted– TTC across seams to be honored

• Consent from seller– Participants free to schedule in STOA

Scheduling of Bids

• Despatched bids directly incorporated in schedule of sellers

• Unmatched one to one schedule• Creation of a notional entity ‘POOL’

– For scheduling bids under FSAS– Despatched bids attributed towards drawal of the

‘POOL’

• Drawees of despatched power to pay UI charges• Scheduling as per present practice on regional

basis

Settlement of Bids• Options for settlement

• Uniform pricing

• Pay as Bid Pricing

– Commission to decide

• Upper limit of CERC UI vector : ceiling price– No commitment or penalty charge

• Payment to sellers through power exchanges– UI pool of respective regions– Transfer of Funds from regional UI pool to exchanges– Payment made 30 days after the day of operation

• UI settlement takes approximately 4 weeks

• Power Exchanges to get facilitation Charges• Deficit met through PSDF

Thank you

Discussion………