| Rated voltage | Choose a switchgear class equal to or above the network voltage: commonly 12 kV for 6–10 kV systems, 17.5 kV for 11–15 kV systems, and 24 kV for 20–22 kV systems. | The rated voltage determines insulation clearances, dielectric withstand capability, and suitability for the distribution network. | Confirm the utility nominal voltage, maximum operating voltage, and required power-frequency and lightning-impulse withstand levels. | Do not select by nominal voltage alone; the equipment insulation class must also match the network’s maximum voltage. |
| Rated normal current | Common ring-main ratings are 200 A, 400 A, and 630 A. A 630 A rating is frequently used where future load growth or interconnected feeders are expected. | The continuous current rating must prevent overheating during normal operation, load transfer, and permissible overload conditions. | Compare the expected peak current, transformer rating, feeder diversity, ambient temperature, and future expansion plan. | Select the next suitable standard rating above the calculated continuous and emergency transfer current. |
| Short-time withstand current | Typical medium-voltage RMU values include 12.5 kA, 16 kA, 20 kA, and 25 kA for 1 or 3 seconds, depending on the network fault level. | The switchgear must withstand the thermal and mechanical effects of a short circuit until the protection system clears the fault. | Obtain the prospective three-phase short-circuit current and the protection clearing time from the network study. | The selected short-time rating should be equal to or greater than the calculated fault current for the specified duration. |
| Peak withstand and making capacity | Peak withstand ratings are commonly approximately 2.5 times the short-time RMS rating at 50 Hz, subject to the applicable standard and design. | Peak current affects the mechanical stress on busbars, contacts, cable terminations, and earthing conductors during a fault. | Check the manufacturer’s declared peak withstand and short-circuit making ratings against the utility specification. | Do not infer making capacity solely from the continuous current rating. |
| Installation altitude | Standard ratings generally apply up to 1,000 m above sea level. Higher elevations may require insulation coordination or derating. | Air density decreases with altitude, reducing external insulation withstand and cooling performance. | Record the highest site elevation and apply the correction required by the relevant standard or project specification. | Request a high-altitude design review for installations above 1,000 m. |
| Ambient temperature | Many indoor medium-voltage designs are specified for approximately −5 °C to +40 °C, with a daily average commonly limited to 35 °C. | Temperature affects current-carrying capacity, enclosure heating, seal performance, battery life, and operating mechanisms. | Assess minimum and maximum site temperature, solar gain, ventilation, indoor heating, and local climatic conditions. | Use heaters, ventilation, thermal derating, or an extended-temperature design where required. |
| Humidity and condensation | Indoor substations may experience high relative humidity, condensation, or polluted air, especially in coastal, underground, and poorly ventilated rooms. | Moisture can reduce surface insulation performance and accelerate corrosion of mechanisms, terminals, and enclosure components. | Inspect the room for water ingress, condensation risk, ventilation, drainage, and proximity to process equipment. | Consider anti-condensation heaters, improved ventilation, sealed cable compartments, and corrosion-resistant finishes. |
| Ingress protection | Typical indoor enclosures are often specified at IP2X or higher for internal access protection. Outdoor installations commonly require higher enclosure protection, frequently IP54 or above. | The IP rating indicates protection against access to hazardous parts and the ingress of solid objects and water. | Confirm the required enclosure rating for the complete assembly, including doors, cable boxes, operating shafts, and pressure-relief paths. | Match the rating to the installation environment rather than selecting the highest rating automatically. |
| Internal arc classification | Where personnel may remain near energized equipment, project specifications may require internal arc classification such as AFL or AFLR for a stated duration and fault current. | Internal arc performance can limit hot gases, pressure, and ejected materials during an internal fault. | Check the required access sides, test current, test duration, installation arrangement, and room pressure-relief design. | Select the tested configuration that matches the actual installation; internal arc performance is not transferable between layouts without confirmation. |
| Switch-disconnector duty | Ring-main load-break switches commonly use a 630 A class, while transformer ways may use a lower current rating combined with an appropriate fuse or circuit-breaker arrangement. | The switch must interrupt the specified normal load current and withstand switching duties defined for the network. | Verify load-break capability, transformer switching duty, cable-charging current, and transfer-operation requirements. | Choose a switch-disconnector, circuit breaker, or fuse-switch combination based on the protection philosophy. |
| Earthing switch capability | Earthing switches may be specified as nonfault-making or fault-making devices. Fault-making capability is often required where interlocking and operating procedures permit closing onto an energized feeder. | The earthing switch must safely establish and carry earth current under the specified operating condition. | Check short-circuit making capacity, short-time withstand, cable discharge requirements, and the network earthing arrangement. | Use a fault-making earthing switch where required by the utility or operational safety procedure. |
| Insulation technology | Common options include air-insulated, gas-insulated, and solid-insulated designs. Gas-insulated units are compact; air-insulated units offer easier visual access; solid-insulated designs avoid routine gas handling. | Technology affects footprint, environmental controls, maintenance approach, end-of-life treatment, and total cost of ownership. | Compare dielectric test data, enclosure layout, service access, environmental declarations, and end-of-life procedures. | Choose the technology that best fits space, sustainability policy, maintenance resources, and local regulations. |
| Environmental compliance | For equipment using fluorinated gas, check the applicable fluorinated-gas restrictions, reporting duties, leakage controls, recovery requirements, and national implementation rules in force at the project location. | Regulatory requirements may affect procurement, installation, service personnel, recordkeeping, and end-of-life handling. | Review current local law, utility rules, gas quantity, equipment category, and the supplier’s environmental documentation. | A technically compliant product may still require additional operational controls under local environmental legislation. |
| Product and assembly standards | Medium-voltage switchgear assemblies are commonly evaluated against IEC 62271-200, while switch-disconnectors and earthing switches are covered by the applicable IEC 62271 series requirements. | Standards define design verification, dielectric tests, temperature-rise tests, short-circuit tests, mechanical operation, and service conditions. | Request the declaration of conformity, routine-test records, design-verification evidence, and the exact tested configuration. | Specify the applicable edition and national deviations in the purchase documents. |
| Cable compatibility | Typical medium-voltage cable systems use rated voltages such as 6/10 kV, 8.7/15 kV, or 12/20 kV, depending on the network. | Incorrect cable-screen arrangement, termination dimensions, or phase spacing can create installation delays and insulation problems. | Confirm cable type, conductor size, screen construction, termination kit, bend radius, gland arrangement, and phase spacing. | Approve the complete cable-termination interface before manufacturing or site delivery. |
| Protection and automation | Options may include striker-pin fuses, self-powered overcurrent protection, numerical relays, motor operators, remote indication, and SCADA interfaces. | Protection and automation determine fault clearance, selectivity, remote switching, outage duration, and operational safety. | Check protection coordination, CT or sensor accuracy, auxiliary supply availability, communications protocol, and fail-safe behavior. | Use circuit-breaker ways and numerical protection where coordination or remote control cannot be achieved with fuses alone. |
| Mechanical endurance | Operating-cycle capability varies by device and duty. A project should specify the required number of mechanical and electrical operations rather than assuming all switches have the same endurance. | Frequent switching, automated transfer, and network reconfiguration impose greater wear than occasional manual operation. | Compare the declared endurance class with the expected annual operations and automatic-transfer sequence. | Use a higher-endurance mechanism where frequent operation is expected. |
| Routine maintenance | Typical activities include visual inspection, cleaning, torque checks, interlock verification, operating-mechanism checks, cable-compartment inspection, and functional testing. | Maintenance prevents degraded insulation, loose connections, failed interlocks, and unreliable switching. | Follow the equipment maintenance manual, utility procedures, and risk-based inspection intervals. | Prioritize designs with accessible test points, clear position indicators, replaceable mechanisms, and documented maintenance procedures. |
| Condition monitoring | Possible tools include partial-discharge monitoring, temperature sensors, gas-density monitoring, contact-wear indication, and operating-cycle counters. | Monitoring can identify developing insulation, thermal, leakage, or mechanism problems before an unplanned outage. | Assess asset criticality, failure consequences, available communications, and the cost of installing and interpreting sensors. | Use monitoring selectively for critical substations, high-load transformers, difficult-access sites, or ageing assets. |
| Indicative maintenance burden | Sealed compact RMUs may require fewer routine internal interventions than accessible air-insulated assemblies, but they still require inspection, operational testing, and interface checks. | Lower routine access does not eliminate the need to verify interlocks, indicators, cable terminations, earthing, and operating mechanisms. | Compare the full maintenance schedule, required specialist tools, spare parts, outage duration, and technician qualifications. | Evaluate labor, outage, testing, and specialist-service costs together rather than comparing inspection frequency alone. |
| Initial purchase cost | Relative cost depends on voltage class, fault rating, enclosure type, automation, protection, internal arc requirements, and quantity. More compact or highly automated designs usually have higher initial cost. | The purchase price is only one part of the financial decision. | Obtain comparable quotations with identical ratings, accessories, testing, delivery terms, installation scope, and documentation. | Normalize quotations before selecting the lowest price. |
| Installation and commissioning cost | Major cost drivers include room modifications, lifting access, cable termination, earthing, protection testing, control wiring, communications, and outage coordination. | A compact unit may reduce civil-work cost, while more complex automation may increase commissioning time. | Request a project-specific installation method statement and commissioning schedule. | Include civil works, testing, training, and energization support in the capital-cost comparison. |
| Lifecycle cost horizon | A practical comparison commonly uses 15–30 years and includes purchase, installation, energy losses, inspections, planned outages, spares, repairs, training, environmental compliance, and disposal. | Equipment with a higher initial price can provide a lower total cost when it reduces space, downtime, maintenance, or replacement risk. | Use a discounted cash-flow model with stated assumptions for inflation, discount rate, outage cost, and replacement timing. | Select on total cost of ownership, not purchase price alone. |
| Spare-parts availability | Confirm availability of operating mechanisms, auxiliary switches, fuses, sensors, control modules, cable-compartment parts, and approved termination components for the intended service period. | Long lead times can extend outages and make otherwise serviceable equipment uneconomic to maintain. | Require a recommended spare-parts list, lead times, obsolescence policy, and local technical-support arrangements. | Place critical spare parts on order before commissioning where replacement lead times are long. |
| End-of-life planning | Plan for de-energization, isolation, dismantling, material recycling, waste classification, and recovery or disposal of any insulating medium. | End-of-life obligations can create material labor, transport, environmental, and documentation costs. | Request dismantling instructions, material declarations, gas or medium recovery procedures, and disposal responsibilities. | Include decommissioning cost and environmental obligations in the lifecycle-cost model from the start. |
