Every utility-scale solar project in India that exceeds the threshold for LT interconnection — typically above 1 MW — must connect to the grid at a high-voltage level. Whether that connection point is 33 kV, 66 kV, or 132 kV depends on the state DISCOM, the feeder available at the site boundary, and the contracted capacity. The engineering drawings that govern this HV interconnection are not a formality. They are the document set that DISCOM, SLDC, SECI, and independent engineers scrutinize before commissioning approval is granted. An incomplete or non-compliant HV drawing package delays synchronisation by weeks and can trigger contract liquidated damages.
Direct answer. Solar HV interconnection drawings cover the full electrical path from the project’s main power transformer (MPT) secondary to the grid injection point. For Indian utility-scale projects, the mandatory package — the HV Drawing Package Checklist — contains six document layers: single-line diagram, protection relay scheme, earthing and bonding layout, cable schedule, equipment layout plan, and relay settings report. CEA Connectivity Regulations 2019 specify protection and metering requirements for each voltage class. A 33 kV interconnection typically requires IDMT overcurrent and earth-fault relays; 66 kV and 132 kV require distance protection with pilot teleprotection. Missing any layer means DISCOM will not issue a synchronisation permit.
This article follows Suresh — an Indian utility-scale solar developer bidding SECI Round-XI capacity — through every layer of the HV Drawing Package Checklist. It explains when each voltage class applies, how to specify protection relays, what CEA mandates for metering, and what a complete drawing set looks like at handover to the DISCOM’s protection engineer.
When HV Interconnection Is Required for Solar Plants
HV interconnection is required when the plant’s contracted capacity and the available grid point together push the connection voltage above the low-voltage distribution range. In practice, the thresholds follow each state’s grid code and the DISCOM’s distribution network voltage map.
Definition. HV interconnection in Indian solar projects refers to the electrical connection made at 33 kV, 66 kV, or 132 kV between the solar plant's main power transformer and the nearest grid substation or pooling station, governed by the CEA (Technical Standards for Connectivity of the Distributed Generation Resources) Regulations 2019.
The general capacity thresholds used by most state DISCOMs and transmission companies are:
| Plant Capacity | Typical Interconnection Voltage | Governing Body |
|---|---|---|
| 1 MW – 5 MW | 33 kV (some states 11 kV) | DISCOM / SLDC |
| 5 MW – 50 MW | 33 kV or 66 kV | DISCOM / SLDC |
| 50 MW – 250 MW | 66 kV or 132 kV | STU / ISTS |
| Above 250 MW | 220 kV or 400 kV | PGCIL / ISTS |
These thresholds vary by state: Rajasthan and Gujarat have well-developed 132 kV pooling infrastructure for SECI projects, while Karnataka and Tamil Nadu frequently use 33 kV feeders for projects up to 10 MW. Always confirm the available voltage level with the DISCOM before finalising the single-line diagram, because a wrong assumption at bid stage translates into a transformer specification that is impossible to correct post-auction.
The interconnection voltage also determines the level of protection complexity. A 33 kV connection can use simpler electromechanical or numerical relay packages. A 132 kV connection requires full distance protection with teleprotection, dedicated communication channels, and SCADA data points that report to the SLDC every 15 minutes.
According to the CEA Connectivity Regulations 2019, the developer is responsible for providing all protection equipment up to the point of common coupling (PCC), including current transformers (CTs), voltage transformers (VTs), relays, circuit breakers, and metering panels. The DISCOM’s engineer approves relay settings before commissioning begins.
33 kV vs 66 kV vs 132 kV — Selection Criteria
Choosing the wrong voltage class is one of the most expensive mistakes at the engineering design stage. The drawing set, transformer specification, switchgear procurement, and civil substation layout all flow from this single decision.
Confirm the grid injection point voltage
Contact the state STU or DISCOM and request the substation voltage at the nearest grid point. This is the non-negotiable starting constraint. Do not select the interconnection voltage before receiving a written grid availability certificate (GAC).
Calculate the maximum fault level at the PCC
The switchgear rating must exceed the prospective fault current at the PCC. Higher-voltage buses carry higher fault levels, which drives switchgear cost. A 132 kV bus at a large pooling station may carry 40 kA fault current, requiring more expensive circuit breakers than a 33 kV rural feeder at 16 kA.
Check the inter-plant transmission line length
A project more than 5 km from the grid substation at 33 kV will face unacceptable voltage drop and line losses. At 132 kV, the same 5 km line carries power at a fraction of the current, cutting I²R losses by a factor of 16 relative to the equivalent 33 kV line. Long evacuation lines push the design toward higher voltage classes.
Match transformer specification to interconnection voltage
The main power transformer (MPT) must be specified with a primary winding voltage matching the grid injection point and a secondary matching the inverter output (typically 415 V or 690 V). A 66/0.415 kV transformer costs roughly 15–20% more than a 33/0.415 kV unit of the same MVA rating, so voltage selection directly influences capital expenditure.
| Parameter | 33 kV | 66 kV | 132 kV |
|---|---|---|---|
| Typical project size | 1–20 MW | 10–100 MW | 50–500 MW |
| MPT impedance (typical) | 6–8% | 8–10% | 10–12% |
| Switchgear standard (IS) | IS 13118 / IEC 62271 | IS 13118 / IEC 62271 | IEC 62271-100 |
| Protection relay complexity | IDMT O/C + E/F | IDMT + directional + differential | Distance (Zones 1-3) + pilot |
| Teleprotection required | No | Often required | Mandatory |
| Typical substation area | 200–400 m² | 400–800 m² | 800–2,000 m² |
The HV Drawing Package Checklist — Heaven Designs Proprietary Framework
The HV Drawing Package Checklist is Heaven Designs’ structured drawing set for utility-scale solar HV interconnection submissions. It defines six layers of drawings that must be complete and mutually consistent before the DISCOM protection engineer will schedule a relay setting review meeting. Missing one layer means the entire submission is returned.
Single-Line Diagram (SLD)
The SLD shows every element from the module strings through the inverter, step-up transformer, HV switchyard, and transmission line to the grid injection point. Every CT ratio, VT ratio, relay designation, circuit breaker rating, busbar size, and cable cross-section must appear. See our guide on the complete solar engineering workflow for Indian EPCs for SLD naming conventions.
Protection Relay Scheme Drawing
This drawing details every relay type, its IED model number, CT/VT connections, trip circuit wiring, and intertrip logic. For 33 kV, this typically covers IDMT overcurrent (51), earth fault (51N), and under/over-voltage. For 132 kV, it covers distance protection (21), directional earth fault (67N), differential (87T), and teleprotection (85).
Earthing and Bonding Layout
The earthing layout shows the switchyard earth grid conductor network, earth electrode positions, earth mat depth, and bonding connections to every equipment frame. It must demonstrate compliance with IS 3043 (earthing practice) and IEEE 80 (guide for AC substation grounding) with a target earth resistance below 1 Ω at the switchyard.
HV Cable Schedule
The cable schedule lists every HV cable segment with its core cross-section, insulation voltage class, armoring, laying method, route length, and ampacity calculation. For underground cable, include the thermal resistivity of the soil and the depth of burial. For overhead line, include the conductor size, sag-tension calculations, and insulator specification.
Equipment Layout Plan
The equipment layout is a dimensioned plan view of the HV switchyard showing the positions of circuit breakers, isolators, bus post insulators, CTs, VTs, surge arresters, control building, and cable trenches. Minimum clearance distances prescribed by IS 5613 must appear on the drawing for the relevant voltage class.
Relay Settings Report
The relay settings report is a tabulated document showing every relay function number, the calculated pickup current or voltage, the time-multiplier setting (TMS), and the coordination margin with the upstream DISCOM relay. This report is the document the DISCOM protection engineer signs off before commissioning. It must be derived from a formal relay coordination study — not estimated.
Watch out. DISCOMs in states like Rajasthan and Gujarat now ask for all six layers simultaneously. Submitting an SLD without the relay settings report, or the relay settings without the cable schedule, results in a rejected submission and a new queue position — which can add 4–8 weeks to the commissioning timeline.
Single-Line Diagram Requirements for HV Solar Projects
The single-line diagram is the master document from which all other drawings derive. For HV solar interconnection, the SLD must do more than show the DC-to-AC conversion chain. It must show the complete electrical path from the lowest-voltage point (module output) to the highest-voltage point (grid injection bus) with every protective device, measurement point, and interlocking logic visible.
Key elements that must appear on a DISCOM-accepted HV SLD:
- Transformer data block: MVA rating, voltage ratio (e.g., 33/0.415 kV), vector group (Dyn11 is standard for solar MPTs), percentage impedance, and cooling class (ONAN/ONAF).
- CT ratios at every measurement point: Protection CTs and metering CTs must be shown separately because they have different accuracy classes. Protection CTs use Class 5P20 or Class 10P20; metering CTs use Class 0.2S.
- VT ratios and burden: Specified in VA at the rated burden. Typically 100 V line-to-line secondary for 33 kV and above.
- Circuit breaker ratings: Rated voltage (kV), rated current (A), rated short-circuit breaking current (kA), and rated operating sequence (O–CO or CO–CO).
- Busbar size and material: Cross-section in mm², conductor material (copper or aluminium), and current rating at the ambient design temperature.
- Protection relay function numbers: Use IEEE C37.2 function numbers on the SLD. Function 51 is overcurrent, 51N is earth fault, 27 is undervoltage, 59 is overvoltage, 21 is distance, 87T is transformer differential.
- Metering point location: The billing meter (CT and VT in the metering panel) must be clearly marked. Most Indian DISCOMs require the metering point at the HV side of the MPT so that transformer losses are borne by the developer.
Field tip. Always draw the SLD with north at the top of the page and cross-reference equipment tag numbers between the SLD, the equipment layout plan, and the protection scheme drawing. A mismatch between tag numbers in these three documents is the most common reason for DISCOM review comments.
The SLD for a SECI project must also comply with the SECI standard drawing format, which includes a title block with project name, capacity, location, revision number, and approval columns for the developer’s engineer, the independent engineer, and the DISCOM interface engineer.
Protection Relay Scheme — Overcurrent, Differential, and Distance
Protection relay selection depends on the interconnection voltage class, the prospective fault current, and the DISCOM’s specific requirements. According to CEA Connectivity Regulations 2019, Schedule 2, the minimum protection requirements are:
| Voltage Class | Mandatory Protection Functions |
|---|---|
| 33 kV | IDMT overcurrent (51), Earth fault (51N), Under/over-voltage (27/59), Under/over-frequency (81U/81O), Reverse power (32) |
| 66 kV | All 33 kV functions + Directional overcurrent (67), Directional earth fault (67N), Auto-reclosure lockout |
| 132 kV | All 66 kV functions + Distance (21), Differential (87T for transformer), Teleprotection (85), High-speed auto-reclose |
IDMT Overcurrent (Function 51): The inverse-definite minimum time (IDMT) characteristic provides a time–current relationship where operation time decreases as fault current increases. The standard characteristics in India are Normal Inverse, Very Inverse, and Extremely Inverse, defined in IEC 60255-151. The pickup current is set above the maximum load current but below the minimum fault current at the relay location. The time-multiplier setting (TMS) is chosen to provide a minimum coordination margin of 0.3–0.4 seconds with the upstream DISCOM relay.
Transformer Differential (Function 87T): The differential relay compares current entering the primary terminal of the MPT with current leaving the secondary terminal, accounting for the vector group phase shift. A 15% second harmonic blocking threshold prevents operation during transformer energisation (magnetising inrush current contains a high second-harmonic component). The 87T relay must operate in under 30 ms for an internal transformer fault.
Distance Protection (Function 21): Required at 132 kV, distance protection operates based on the apparent impedance seen at the relay terminals. Zone 1 covers 80% of the protected line and trips in under 50 ms with no intentional delay. Zone 2 covers 120% of the protected line and trips after 0.3–0.4 seconds. Zone 3 provides backup for remote-end faults with a 0.6–1.0 second delay. The zone reach settings are calculated from the measured positive-sequence impedance of the transmission line.
According to IEEE C37.91 (Guide for Protective Relay Applications to Power Transformers), differential protection for solar power transformers must account for the inverter’s current-limiting behaviour during faults. Unlike conventional generators, inverters cannot deliver sustained fault current above 1.1–1.5 times rated current, which means some protection functions that rely on high fault current (such as instantaneous overcurrent) may not operate reliably on the solar plant’s output feeder.
CEA Connectivity Regulation Requirements for Solar HV Projects
The CEA (Technical Standards for Connectivity of the Distributed Generation Resources) Regulations 2019 are the primary regulatory instrument for HV interconnection in India. Every solar project connecting to the grid must demonstrate compliance before the DISCOM issues a synchronisation permit.
Key requirements that affect the drawing set:
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Anti-islanding protection: All grid-connected solar plants must include anti-islanding protection (also called loss-of-mains or LOM protection). This is typically implemented using under/over-voltage (27/59) and under/over-frequency (81U/81O) relays with trip settings defined in Schedule 4 of the CEA Connectivity Regulations. The disconnection must occur within 0.2 seconds for voltage deviations beyond ±15% of nominal.
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Power factor control: Plants above 1 MW must have reactive power control capability. The protection scheme drawing must show the automatic voltage regulation (AVR) loop connecting the inverter or capacitor bank to the VT measurement point at the PCC.
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LVRT and HVRT compliance: Low-voltage ride-through (LVRT) and high-voltage ride-through (HVRT) are mandatory for projects above 1 MW connected to 33 kV and above. The inverter datasheet must confirm ride-through capability, and the relay settings must not trip during transient voltage dips within the LVRT envelope.
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Fault ride-through: Projects connected at 66 kV and above must remain connected during three-phase faults cleared within the standard clearing time of the protection system (typically 100–200 ms for 66 kV, 80–120 ms for 132 kV).
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Data recording: A digital fault recorder (DFR) or event recorder must be installed to capture voltage, current, frequency, and relay operation timestamps for every fault event. The data must be accessible to the SLDC on request.
Note. CEA is revising the Connectivity Regulations to include requirements for battery storage, hybrid systems, and reactive compensation at the interconnection point. Check cea.nic.in for the latest amendment notifications before finalising your protection scheme drawing.
Metering at HV — Accuracy Classes and Placement
The billing meter for a utility-scale solar plant is the revenue instrument that determines how many units the developer is paid for. Errors in metering class specification, CT burden mismatch, or incorrect metering panel placement can result in measurement errors that affect revenue for the entire 25-year project life.
0.2S
Metering CT accuracy class
CEA Meters Regulations 2006, India
0.5
Metering VT accuracy class
IS 3156 Part 2
0.05%
Revenue meter accuracy class
IS 16444 / IEC 62053-22
15 min
SLDC data reporting interval
CEA Grid Code 2023
According to the Bureau of Indian Standards (BIS), metering CTs for revenue applications must comply with IS 16227 (equivalent to IEC 61869-2) and must be calibrated and sealed by a NABL-accredited laboratory before installation. The sealing prevents tampering and is required for the DISCOM to accept the meter reading as binding.
Metering panel location: Most Indian DISCOMs require the energy meter to be located on the HV side of the MPT (at the grid injection voltage level) so that transformer iron and copper losses are metered as part of the plant output. Some DISCOMs accept metering on the LV side with a standard transformer loss allowance deducted from the reading — confirm this in the power purchase agreement before specifying the metering panel location.
The metering panel drawing must show the meter model and serial number space, the CT secondary terminal block, the VT secondary terminal block, the AMR/SCADA communication port (RS-485 or Ethernet), and the sealing arrangement. Every connection between the CT secondary and the meter must be made in sealed terminal blocks with tamper-evident covers.
Earthing at the HV Switchyard
The earthing system for an HV switchyard serves two functions: it limits the touch and step voltages that personnel are exposed to during a fault, and it provides a low-impedance return path for fault currents that enables protection relays to operate reliably. Both functions must be verified by calculation, not assumed.
The design methodology follows IS 3043 (Code of Practice for Earthing) for Indian projects and is supplemented by IEEE 80 (Guide for Safety in AC Substation Grounding), which provides the fault current tolerable limits for the human body and the formulae for calculating grid resistance.
Key design steps for HV switchyard earthing:
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Soil resistivity measurement: Conduct a four-pin Wenner method test at the switchyard site at multiple spacings (1 m, 3 m, 5 m, 10 m, 20 m). Use a soil resistivity meter compliant with IEEE 81. The measurement must be taken in the dry season (lowest moisture content) to give a conservative design.
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Earth grid conductor sizing: The ground conductor cross-section must carry the maximum earth fault current for the fault duration without exceeding the allowable temperature rise. For copper conductors, IS 3043 gives the formula: S = I × √(t / k), where S is the conductor cross-section in mm², I is the fault current in A, t is the fault duration in seconds, and k is a material constant (k = 226 for copper, k = 148 for aluminium).
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Mesh and rod arrangement: A rectangular mesh grid buried at 0.5–0.6 m depth with a spacing of 3–5 m is standard for solar switchyards. Vertical earth rods (typically 3 m × 40 mm diameter, copper-bonded steel) are driven at each corner and at intermediate mesh points to reduce the resistance by penetrating into lower-resistivity soil layers.
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Touch and step voltage limits: The calculated touch voltage must not exceed 50 V in wet conditions (IEC 60479 tolerable body current × body+ground resistance). The step voltage limit is typically higher, around 100–150 V. IEEE 80 provides tables of tolerable voltages for different body weights and soil resistivity combinations.
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Earth resistance verification: After installation, measure the final earth resistance using the fall-of-potential method. The target is below 1 Ω for HV switchyards, and below 4 Ω for LV distribution earthing.
Watch out. Soil resistivity in Rajasthan and Gujarat's dry regions can reach 500–2,000 Ω·m. A standard mesh grid designed for 100 Ω·m soil will not achieve the 1 Ω target in these conditions. The earthing design must use deep bore wells with bentonite backfill or chemical earthing electrodes when the soil resistivity exceeds 300 Ω·m. Provide DISCOM with the soil resistivity test report alongside the earthing drawing.
Typical Drawing Set for SECI Projects
SECI (Solar Energy Corporation of India) has developed standard drawing submission requirements for projects bid through its auction programmes. Projects bid under SECI Round X, Round XI, and subsequent rounds must submit drawings that conform to the SECI Engineering Drawing Standards (EDS), which are available from the SECI project management portal.
The standard SECI drawing set for HV interconnection typically includes the following documents, each with its own drawing number, title block, and revision control:
| Drawing Category | Typical Drawing Numbers | Content |
|---|---|---|
| Single-Line Diagrams | 100-SLD-001 to 003 | DC SLD, AC SLD, HV SLD |
| Protection Relay Scheme | 200-PRS-001 to 004 | Overcurrent, differential, distance, teleprotection |
| Earthing Layout | 300-ETH-001 to 002 | Switchyard earth grid, module frame earthing |
| Cable Schedules | 400-CAB-001 to 003 | HV cables, LV power cables, control cables |
| Equipment Layout | 500-EQL-001 to 003 | Switchyard plan, elevation, sections |
| Relay Settings Report | 600-RSR-001 | Tabulated relay settings, grading curves |
| Metering Panel | 700-MET-001 to 002 | Metering panel GA, wiring diagram |
All drawings must be submitted in PDF format (for DISCOM review) and DWG/DXF format (for the SLDC’s GIS database update). The revision status must be “For Approval” (FA) when first submitted; revisions after DISCOM comments must be resubmitted as “Rev A”, “Rev B”, and so on. The “Issued for Construction” (IFC) revision is only released after written approval from the DISCOM’s interface engineer.
The SECI also requires that the independent engineer (IE) — typically a lender-appointed technical consultant — countersign the HV drawing set before it is submitted to DISCOM. This means the IFC timeline must include a two-to-four-week IE review cycle. For a guide on what lenders’ independent engineers review, see our article on lenders’ due diligence and engineering in India.
Need a SECI-compliant HV drawing package?
Download a redacted sample HV interconnection drawing set — includes SLD, protection relay scheme, earthing layout, and relay settings report in SECI format.
Get the sample pack →How Heaven Designs Helps with HV Interconnection Engineering
Most Indian EPC contractors have strong civil and mechanical teams but limited HV electrical engineering capacity. Hiring a protection engineer with DISCOM interface experience costs ₹18–25 lakhs per year in salary alone, plus the cost of protection relay software licences (ETAP, PowerWorld, or ERACS), which run ₹3–8 lakhs per year. For EPCs that do not win HV projects on a continuous basis, maintaining this capacity in-house is inefficient.
Heaven Designs provides HV interconnection engineering as a project-specific service, with a team that has delivered HV drawing packages for projects across Rajasthan, Gujarat, Karnataka, Andhra Pradesh, and Telangana. Our deliverables align with the CEA Connectivity Regulations 2019 and SECI Engineering Drawing Standards.
- Electrical CEIG Drawings — CEIG-approval-ready electrical drawings including HV SLD, protection scheme, and earthing layout, reviewed by our in-house protection engineers before submission.
- Solar Rooftop Detailed Engineering Design — Full IFC drawing package from DC string to HV injection point, including BOQ, mounting, and structural.
- Solar Civil and Structural Engineering — HV switchyard civil foundations, equipment plinths, cable trench design, and control building structural drawings.
- Download a sample HV drawing package — Redacted SECI-format sample set with all six layers of the HV Drawing Package Checklist.
Contact us to discuss your HV interconnection drawing requirements. We typically deliver the first-submission drawing set within 10–14 working days from receipt of the grid availability certificate and project specification.
FAQ
What is the difference between a solar project’s point of common coupling (PCC) and the grid injection point?
The point of common coupling (PCC) is the electrical node where the solar project connects to the utility grid — it is the boundary between the project’s private electrical network and the publicly owned grid. The grid injection point may be at the same location (if the project connects directly to a DISCOM substation bus) or at a different physical location (if there is a developer-owned transmission line between the project and the DISCOM substation). For billing and protection purposes, the PCC is the metering point.
Which relay is mandatory for 33 kV solar interconnection in India?
CEA Connectivity Regulations 2019, Schedule 2 mandates a minimum protection package for 33 kV solar interconnection: IDMT overcurrent (IEEE Function 51), earth fault (51N), under-voltage (27), over-voltage (59), under-frequency (81U), and over-frequency (81O) relays. Anti-islanding protection through the combined action of 27/59/81U/81O is also mandatory. Reverse power (Function 32) is required for projects with net metering to detect reverse flow conditions.
How long does DISCOM relay setting approval take in India?
The time from submission of the relay settings report to written approval from the DISCOM protection engineer varies by state. In Rajasthan and Gujarat, the process typically takes 4–8 weeks. In Tamil Nadu and Karnataka, it can take 8–16 weeks due to the higher volume of new projects and limited DISCOM protection engineering staff. Projects on SECI pooling substations sometimes benefit from a faster process because SECI maintains a dedicated interface team. Submit the relay settings report before the civil switchyard work is complete so that the approval does not delay commissioning.
What is the required earth resistance for a 132 kV solar switchyard in India?
IS 3043 and the DISCOM grid codes typically require an earth resistance of 1 Ω or less for HV switchyards (66 kV and above). Some state specifications require 0.5 Ω for 132 kV and above. The earth resistance must be measured at the driest time of year using the fall-of-potential method after the earth grid is complete and before the substation equipment is commissioned. The test report must be submitted to the DISCOM as part of the commissioning documentation.
Does the solar developer own the HV switchyard or the DISCOM?
In India, the standard arrangement for SECI and most DISCOM PPAs is that the developer owns and operates the HV switchyard up to and including the disconnect switch at the PCC. The DISCOM owns the downstream side of the PCC (the connection into their substation bus). The maintenance responsibility for the developer’s switchyard is specified in the power purchase agreement. Some PPAs transfer ownership of the switchyard to the DISCOM after commissioning — check your PPA carefully before specifying equipment that must meet DISCOM asset ownership standards.
What software is used to calculate relay settings for solar HV projects?
The most commonly used software tools for relay setting calculations in Indian solar projects are ETAP (by Operation Technology Inc.), ERACS (by ERA Technology), and PowerWorld Simulator. ETAP is the most widely specified by DISCOMs and independent engineers because it produces output reports in a format that DISCOM protection engineers are familiar with. The relay settings report must include the time-current grading curves generated from the short-circuit study, showing the coordination between the project relay and the upstream DISCOM relay at every fault level from minimum to maximum.
Can a string inverter solar plant use the same protection package as a central inverter plant?
No. String inverters limit fault current to 1.1–1.2 times rated output current and do not provide the sustained fault current that some protection functions rely on. For string inverter plants, the protection engineer must verify that the pickup thresholds for overcurrent relays are set above the maximum aggregated inverter output, which may be difficult to achieve with standard IDMT relay characteristics if the fault current from the grid side is not significantly higher than the normal load current. Some DISCOMs accept alternative protection schemes for string inverter plants — always consult the DISCOM protection engineer during the scheme design stage.
What drawings must be submitted to CEIG for an HV solar project?
The Chief Electrical Inspector to Government (CEIG) typically requires the following drawings for an HV solar project: the complete HV SLD showing all protection and metering, the equipment layout plan of the HV switchyard with clearance dimensions, the earthing layout, the lightning protection drawing, and the protection relay panel GA and wiring diagram. Some states also require the CEIG submission to include the metering panel drawing and the CT/VT test certificates. See our detailed guide on the CEIG drawing approval process in India for state-specific submission requirements.
