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TTC/ATC Computations and Ancillary Services in the Indian context 1 TTC/ATC Computations and Ancillary Services in the Indian context 1

Outline • Part A: TTC/ATC computations • Transfer capability-Definitions • Relevance of transfer capability Outline • Part A: TTC/ATC computations • Transfer capability-Definitions • Relevance of transfer capability in Indian electricity market • Difference between Transfer capability and Transmission Capacity • Assessment of TTC/TRM/ATC • Method for improving Transfer capability • Concerns • Part B: Ancillary services in the Indian context 2

Part A Total Transfer Capability (TTC)/ Available Transfer Capability (ATC) computations 3 Part A Total Transfer Capability (TTC)/ Available Transfer Capability (ATC) computations 3

Transfer Capability - Definitions 4 Transfer Capability - Definitions 4

North American Electric Reliability Corporation’s (NERC) definition of TTC • The amount of electric 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

Total Transfer Capability as defined in the IEGC and Congestion charge Regulations • “Total Total Transfer Capability as defined in the IEGC and Congestion charge Regulations • “Total Transfer Capability (TTC)” means the amount of electric power that can be transferred reliably over the inter-control area transmission system under a given set of operating conditions considering the effect of occurrence of the worst credible contingency. • “Credible contingency” means the likely-to-happen contingency, which would affect the Total Transfer Capability of the inter-control area transmission system – Outage of single transmission element (N-1) in the transmission corridor or connected system whose TTC is being determined – Outage of the largest unit in the importing control area 7

Available Transfer Capability as defined in the IEGC and Congestion charge regulations • “Available Available Transfer Capability as defined in the IEGC and Congestion charge regulations • “Available Transfer Capability (ATC)” means the transfer capability of the inter-control area transmission system available for scheduling commercial transactions (through long term access, medium term open access and short term open access) in a specific direction, taking into account the network security. Mathematically ATC is the Total Transfer Capability less Transmission Reliability Margin. 8

Non Simultaneous & Simultaneous transfer Capability Non-simultaneous Transfer Capability • • Amount of electric Non Simultaneous & Simultaneous transfer Capability Non-simultaneous Transfer Capability • • Amount of electric power that can be reliably transferred between two areas of the interconnected electric system when other concurrent normal base power transfers are held constant Determined by simulating transfers from one area to another independently and non-concurrently with other area transfers. Simultaneous Transfer Capability • Is the amount of electric power that can be reliably transferred between two or more areas of the interconnected electric system as a function of one or more other power transfers concurrently in effect. ” • Reflects simultaneous or multiple transfers with interdependency of transfers among the other areas is taken into account. • No simple relationship exists between non-simultaneous and simultaneous transfer capabilities • The simultaneous transfer capability MAY be lower than the sum of the individual non-simultaneous transfer capabilities. • Simultaneous TTC declared by NR, SR, NER • Simutanous TTC can be declared for 2 regions combined also( e. g 9 ER/NER)

Simultaneous TTC Area A Area C 2000 MW 4000 MW Area B 5000 MW Simultaneous TTC Area A Area C 2000 MW 4000 MW Area B 5000 MW 10

TTC affected by transactions 11 TTC affected by transactions 11

Simultaenous TTC limits to two regions Link Time TTC ER-NR ER-NER PK OFF-PK 2500 Simultaenous TTC limits to two regions Link Time TTC ER-NR ER-NER PK OFF-PK 2500 400 Scheduling Limit 2200 350 • January’ 11 TTC figures • N-1 contingency of 400 KV FSTPP-Malda • FSTPP-KHSTPP D/C limitation during outage of 400 Kv Malda-Purnea D/C • High voltages along Northern corridor • As 400 KV FSTPP-Malda serves both NR & ER in case of increase in TTC of ERNER ER-NR TTC has to be decreased 12 • Thus we could declare a simultaneous TTC of ER-NR & ER-NER combined

Simultaneous TTC limits to two regions INITIAL REVISED LINK TIME TTC SCHEDUL TTC ING Simultaneous TTC limits to two regions INITIAL REVISED LINK TIME TTC SCHEDUL TTC ING LIMIT SCHEDUL ING LIMIT ER-NR PK 2800 2500 2700 2400 ER-NR OFF-PK 2800 2500 2200 ER-NER PK 470 420 550 450 ER-NER OFF-PK 470 420 550 450 • February, 2011 limits • NER TTC INCREASED DUE REQUIREMENT OF NER(ASSAM) TO INCREASED GOI ALLOCATION & • NR TTC CORRESPONDINGLY DECREASED 13

Simultaneous TTC limits to two regions INITIAL (Sep-10) REVISED (Jun-11) LINK TIME TTC SCHEDUL Simultaneous TTC limits to two regions INITIAL (Sep-10) REVISED (Jun-11) LINK TIME TTC SCHEDUL TTC ING LIMIT SCHEDUL ING LIMIT ER-SR PK 2650 2600 1900 ER-SR OFF-PK 2950 2900 2000 WR-SR PK & OFF- 1000 PK 1000 • June, 2011 limits • ER TTC REDUCED DUE TO LOW VOLTAGE IN CHENNAI AREA & HIGH LOADING ON 400 KV VIJAYAWADA – NELLORE I & II. • July, 2011 limits • WR TTC REDUCED TO 800 MW DUE TO COMMISSIONING OF SIMHADRI U # 3. 14

Relevance of Transfer Capability in Indian Electricity Market 15 Relevance of Transfer Capability in Indian Electricity Market 15

Open Access in Inter-state Transmission Regulations, 2008 • 3( 2) The short-term open access 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. ] 16

LT/MT/ Connectivity procedures-2010 ATC checking MTOA approvals: : • CTU(nodal agency) shall notify TTC LT/MT/ Connectivity procedures-2010 ATC checking MTOA approvals: : • CTU(nodal agency) shall notify TTC on 31 st 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 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 17

Tariff Policy Jan 2006 7. 3 Other issues in transmission (2) All available information 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. 18

Open Access Theory & Practice Forum of Regulators report, Nov-08 “For successful implementation of Open Access Theory & Practice Forum of Regulators report, Nov-08 “For successful implementation of OA, the assessment of available transfer capability (ATC) is very important. A pessimistic approach in assessing the ATC will lead to under utilisation of the transmission system. Similarly, over assessment of ATC will place the grid security in danger. ” 19

Reliability Margin 21 Reliability Margin 21

NERC definition of Reliability Margin (RM) • Transmission Reliability Margin (TRM) – The amount 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. 22

Quote on Reliability Margin from NERC document • “The beneficiary of this margin is 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” 23

Reliability margin as defined in Congestion charge regulations • “Transmission Reliability Margin (TRM)” means 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; 25

Reliability Margins- Inference • Grid Operators’ perspective – Reliability of the integrated system – 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 27

Difference between Transfer Capability and Transmission Capacity 28 Difference between Transfer Capability and Transmission Capacity 28

Area Despatch- Example of TTC Area A Area B 515 MW 750 MW 630 Area Despatch- Example of TTC Area A Area B 515 MW 750 MW 630 MVA 515 MW 29

Transfer capability & Transmission capacity – what’s the difference? • Transfer capacity – Refers Transfer capability & Transmission capacity – what’s the difference? • Transfer capacity – Refers to thermal ratings • Transfer capability – Refers to the system’s capability of transfer-varies considerably with system conditions – Can not be arithmetically added for the individual line capacities and ratings – Always less than the aggregated transmission interface between two areas 1015 MW 750 MW 630 MVA TTC = 630 MVA 30

TTC is directional Area A Area B 500 MW Gen 1000 MW Transfer Capability TTC is directional Area A Area B 500 MW Gen 1000 MW Transfer Capability from Area B to Area A = 500 MW 500 MW Transfer Capability from Area A to Area B = 1500 MW 31

Transmission Capacity Vis-à-vis Transfer Capability Transmission Capacity Transfer Capability 1 Declared by designer/ manufacturer 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 32

Transfer Capability is less than transmission capacity because • Power flow is determined by 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 33

77% of electric power transfers from Area A to Area F will flow on 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. 34

Assessment of Transfer Capability 37 Assessment of Transfer Capability 37

Transfer Capability Calculations must • Give a reasonable and dependable indication of transfer capabilities, 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 38

Operating Limits Thermal Limit • Maximum electrical current that a transmission line or electrical Operating Limits Thermal Limit • Maximum electrical current that a transmission line or electrical facility can conduct over specified time periods before it sustains permanent damage by overheating or before it violates public safety requirements. • Source CBIP Technical Report Voltage limit • To be maintained as per IEGC • Minimum voltage limits can establish the maximum amount of electric power that can be transferred without causing damage to the electric system or customer facilities • Widespread collapse of system voltage can result in a black out of portions or the entire interconnected network • Critical voltage for these nodes may also be different. Thus the proximity of each node to the voltage collapse point may be different(VCPI Index) • 0 < VCPI < 1 0 stability 1 instability • Voltage collapse credible event 41

Total Transfer Capability: TTC Thermal Limit Power Flow Voltage Limit Stability Limit Total Transfer Total Transfer Capability: TTC Thermal Limit Power Flow Voltage Limit Stability Limit Total Transfer Capability Time Total Transfer Capability is the minimum of the Thermal Limit, Voltage Limit and the Stability Limit 44

Intra-day STOA Day-ahead STOA Collective (PX) STOA First Come First Served STOA Advance Short Intra-day STOA Day-ahead STOA Collective (PX) STOA First Come First Served STOA Advance Short Term Open Access (STOA) TTC ATC Medium Term Open Access (MTOA) Long Term Access (LTA) Reliability Margin (RM) RM Available Transfer Capability is Total Transfer Capability less Reliability Margin 45

Input Data and Source S No. Input Data Suggested Source 1 Planning Criteria Manual Input Data and Source S No. Input Data Suggested Source 1 Planning Criteria Manual on Transmission Planning Criteria issued by CEA 2 Network Topology Existing network with full elements available Planned outages during the entire assessment period New transmission elements expected / CTU & STU data 3 Transmission line limits Minimum of thermal limit, stability limit and voltage limit 4 Thermal unit availability Load Generation Balance report, Maintenance schedule Anticipated new generating units 5 Thermal despatch Ex bus after deducting the normative auxiliary consumption Output could be further discounted by the performance index of generating units of a particular size as compiled by CEA 6 Gas based thermal despatch Past trend 7 Hydro despatch Peak and off peak actual hydro generation on median consumption day of same month last year The current inflow pattern to be duly accounted 8 Load Forecast by SLDCs/LGBR of RPCs/past trend/Anticipated 9 Credible contingencies Planning criteria + Operator experience 46

Thermal limit derived from ampacity Thermal limit in MW at 0. 975 pu voltage Thermal limit derived from ampacity Thermal limit in MW at 0. 975 pu voltage and unity p. f. More than 10 years of age 65 degree conductor Conductor Type 75 degree conductor 40 o ambient 10 o ambient 400 k. V ACSR Twin Moose 777 1675 1079 1815 400 k. V ACSR Quad Moose 1554 3349 2159 3630 400 k. V ACSR Quad Bersimis 1873 3989 2553 4325 400 k. V ACSR Triple Snowbird 1165 2512 1619 2723 220 k. V ACSR Zebra 196 398 267 431 50

St. Clair’s curve Line loading in terms of SIL of an uncompensated line as 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 52

TTC/ATC calculation methodology-As per congestion charge procedures • Total Transfer Capability between two areas 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 54

Credible contingencies • From Section 3. 5 of IEGC – – – Outage of Credible contingencies • From Section 3. 5 of IEGC – – – Outage of a 132 k. V D/C line or Outage of a 220 k. V D/C line or Outage of a 400 k. V S/C line or Outage of a single ICT or Outage of one pole of HVDC bi pole or Outage of 765 k. V S/C line without necessitating load shedding or rescheduling of generation during steady state operation 55

TTC calculation process Considerations for calculation of TRM – as per congestion procedures • 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 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 57

Procedure for declaration of TTC, TRM, ATC and anticipated Constraints • Role of SLDC 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 58

Procedure for declaration of TTC, TRM, ATC and anticipated Constraints • Role of RLDCs Procedure for declaration of TTC, TRM, ATC and anticipated Constraints • Role of RLDCs • Consider the inputs provided by SLDCs • Assess TTC, TRM and ATC for – – intra regional corridors (group of control areas) individual control areas within the region (if required) Inter-regional corridors at respective ends for a period of three months in advance. • Forward the results along with the input data considered, to NLDC • Also indicate the anticipated constraints in the intraregional transmission system 59

Procedure for declaration of TTC, TRM, ATC and anticipated Constraints • Role of NLDC 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/ intraregional corridors to the RLDCs 60

Procedure for declaration of TTC, TRM, ATC and anticipated Constraints • Role of NLDC 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 61

Transfer Capability assessment Trans. Plan + approv. S/D LGBR Last Year Reports Weather Forecast Transfer Capability assessment Trans. Plan + approv. S/D LGBR Last Year Reports Weather Forecast Last Year pattern Anticipated Network topology + Capacity additions Anticipated Substation Load Anticipated Ex bus Thermal Generation Planning criteria Credible contingencies Simulation Total Transfer Capability Analysis less Brainstorming Reliability Margin equals Anticipated Ex bus Hydro generation Operating limits Operator experience Planning Criteria is strictly followed during simulations Available Transfer Capability 62

Sample TTC uploaded at NLDC website 63 Sample TTC uploaded at NLDC website 63

64 64

65 65

4 NORTHERN REGION 2 NORTHEASTERN REGION WESTERN REGION 8 16 EASTERN REGION 4 SOUTHERN 4 NORTHERN REGION 2 NORTHEASTERN REGION WESTERN REGION 8 16 EASTERN REGION 4 SOUTHERN REGION 66

Possible scenarios for a control area with N interconnections n • Total No. of Possible scenarios for a control area with N interconnections n • Total No. of scenarios possible = 2 • ER 4 inter-regional interconnections 16 possible scenarios • WR 3 inter-regional interconnections 8 possible scenarios • Out of above only limited No. of scenarios applicable • For ER only 3 to 4 out of 16 scenarios possible • Different scenarios dependent upon seasonal characteristics due to the nature of skewed geo-spatial positioning of hydro/Thermal Generators in ER • From the analysis below we see that simultaneous export/import capability calculation is not possible for ER 67

Possible scenarios for Eastern Regional Grid Sl. NO. NR WR SR NER Remarks 1 Possible scenarios for Eastern Regional Grid Sl. NO. NR WR SR NER Remarks 1 Exp Exp Simultaenous Export capability. Probability extremely low 2 Exp Exp Imp Probability very low 3 Exp Imp Exp Probability very low 4 Exp Imp Probability low. Only in high hydro season & high demand in WR/NR 5 Exp Imp Exp Probable in winter load / low hydro conditions 6 Exp Imp lesser Probability 7 Exp Imp Exp Probability low 8 Exp Imp Imp Probable in high hydro season 68

Possible scenarios for Eastern Regional Grid Sl. NO. NR WR SR NER Remarks 9 Possible scenarios for Eastern Regional Grid Sl. NO. NR WR SR NER Remarks 9 Imp Exp Exp Very low probability-Temporarily possible only in case of demand crash/trippings in NR 10 Imp Exp Imp Very low probability 11 Imp Exp Very low probability 12 Imp Exp Imp Very low probability 13 Imp Exp low probability-in case of demand crash/trippings in NR 14 Imp Exp Imp very low probability 15 Imp Imp Exp Very low probability 16 Imp Imp Simultaenous import cabaility Probability extremely low 69

N-1 criteria “Element” in theory “Event” in practice In real time a Single event N-1 criteria “Element” in theory “Event” in practice In real time a Single event can lead to multiple outages 70

(n-1) Element or event ? • Difference exists in n-1 criteria in planning and (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 k. V 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 132 k. V system- may result in loss of power supply to CW system vis a vis tripping of multiple units 71

(n-1)--Element or event ? … contd • Non availability/Outage/Non operation of Bus bar protection (n-1)--Element or event ? … contd • Non availability/Outage/Non operation of Bus bar protection – Results in tripping of all lines from remote stations • Weather disturbance or floods – Might result in loss of substation/multiple lines in the same corridor • Breaker and a half scheme – Outage of combination of breakers may result in tripping of multiple line for a fault in one line 72

NR: FLOWGATES Central UP-Western UP UP-Haryana/Punjab WR: Chandrapur-Padghe Chandrapur-Parli Bina-Gwalior Soja-Zerda SR: Vijaywada-Nellore Hossur-Selam NR: FLOWGATES Central UP-Western UP UP-Haryana/Punjab WR: Chandrapur-Padghe Chandrapur-Parli Bina-Gwalior Soja-Zerda SR: Vijaywada-Nellore Hossur-Selam Cadappa-Kolar Neyvelli-Sriperumbudur ER: Farakka-Malda-Purnea Talcher-Rourkela Farakka-Kahalgaon Kolaghat-Baripada-Rengali 73

Suggestions for improving transfer capability-1 • installation of shunt capacitors in pockets prone to 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 74

Suggestions for improving transfer capability-2 • minimising outage of existing transmission system for facilitating 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: Ø UFLS, Ø UVLS, Ø SPS 75

Part B Ancillary Services in the Indian context 76 Part B Ancillary Services in the Indian context 76

Outline • Definition of ancillary services • Categories of ancillary services • Ancillary services Outline • Definition of ancillary services • Categories of ancillary services • Ancillary services in the Indian context 77

Ancillary services……definitions • Those services that are necessary to support the transmission of capacity 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 13 th 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] 78

Ancillary services……definitions (2) • “Ancillary Services” means in relation to power system (or grid) 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) 79

Relevance of ancillary services Four pillars of market structure 80 Relevance of ancillary services Four pillars of market structure 80

Categories of ancillary services • Frequency Control Services • Network control Services • System Categories of ancillary services • Frequency Control Services • Network control Services • System Restart Services 81

Levels of frequency control Primary frequency response • Immediate response by adjustment of active Levels of frequency control Primary frequency response • Immediate response by adjustment of active power of generating units & consumption of controllable loads to check the deviation in frequency – speed governor (having droop settings)-FGMO/RGMO – self-regulating effect of frequency-sensitive loads (e. g. induction motors)or the action of frequency-sensitive relays Secondary frequency response • Centralized automatic control that adjusts the active power production of the generating units to restore the frequency and the interchanges with other systems to their target values following an imbalance by: – setpoint or reference point adjustment of generators, – starting and stopping of power plants • Goal of secondary frequency control is to minimize the area control error (ACE) [ACE is the instantaneous difference between net actual and scheduled interchange, taking into account the effects of frequency bias] • Absent by design in India 82 • In US/UK known as AGC / LFC

Levels of frequency control Tertiary frequency rseponse • Manual changes in the despatching and Levels of frequency control Tertiary frequency rseponse • Manual changes in the despatching and commitment of generating units • Used to restore the primary and secondary frequency control reserves, to manage congestions in the transmission network, and to bring the frequency and the interchanges back to their target value in case secondary control is unable • India Manual load shedding / ABT mechanism 83

Frequency Control Services Governing system Re-dispatch AGC or LFC Deployment times a key factor Frequency Control Services Governing system Re-dispatch AGC or LFC Deployment times a key factor for categorizing 84

Frequency Reserves Spinning/Reliability reserves • Fast acting units/ controllable loads capable of instantaneous response 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. > 30 mins 85

Generating unit -levels of control 86 Generating unit -levels of control 86

Voltage Control Primary voltage control • Local automatic control that maintains the voltage at 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% 87

Drivers for Ancillary Services • Reliability and Security • Deregulated Power Systems • Services 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: ” 88

POSOCO’s Approach Paper • Approach paper on ‘Ancillary Services in Indian Context’ published by 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) 90

POSOCO’s Approach Paper • Comments received from various stakeholders • Service identified for immediate 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 91

Frequency Support Ancillary Service (FSAS) • Focus on utilizing idle generation – High liquid 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 92

Implementation of FSAS • Facilitation through Power Exchange – Separate category of user group 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 93

Implementation of FSAS • Dispatch in case of congestion – ATC limits to be 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 94

Implementation of FSAS • Options for settlement – ‘Pay-as-bid price’ – ‘Uniform Pricing’ All 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 95

Ancillary Services Fund • ‘Ancillary Services Fund’ account to be opened and maintained by 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 96

Ancillary services-further scope Pumped storage plants • Reimbursement of loss amount corresponding to power Ancillary services-further scope Pumped storage plants • Reimbursement of loss amount corresponding to power consumed and generated on UI discounted by efficiency factor Network Control ancillary services(NCAS) • Power flow control ancillary services(PFCAS) – Settlement similar to FSAS • Voltage control ancillary services – Operation of synchronous machines in synchronous condenser mode – initially hydro but could be possible for Gas & old Thermal stations in future – Reimbursement of charges on paise/KVARH basis discounting voltage factor – Power consumed due to windage/friction losses & resulting UI to be nullified and socilized in the pooled losses – Mobile reactive installations System restart ancillary services(SRAS) • Incnetivization for successful mock black starts 97

System restart services • Black start capability of generating units – Dead bus charging 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 98

Ancillary services-Into the future Primary frequency control • Frequency responsive demand disconnection by Bulk 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 99 Transfer capability

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