Case study: upgrading transformer capacity from 250kVA to 630kVA at VSIP1

Quick summary of the VSIP1 upgrade project

Upgrading capacity from 250 kVA to 630 kVA at VSIP1 Binh Duong; Quanganhcons was responsible for surveying, supplying and installing the 630 kVA transformer, configuring protection, the LV side and handover. ^[4][5]

The actual scope included a field survey, determining the transformer location, checking LV cable routes and LV panel configuration, configuring corresponding protection and performing acceptance testing for handover to owner ASUZAC ACM. During maintenance shifts and site surveys, accessibility to the transformer and foundation conditions must be verified before moving equipment into position.

During the site survey the minimum checks must include present load currents, grid supply capability, LV cable cross‑section and length, connection points, and the switching/disconnection capability at panels. Verify protection configuration on each LV feeder to avoid overloads after the upgrade and record the site status in a survey report.

• Check the foundation location and dimensions for the transformer; measure LV cable distances and cable routing.
• Verify actual load current on the substation, load factor and the grid supply capability at the time of survey.
• Cross‑check protection requirements: the type of relays/protection functions must be specified in technical documentation before preparing installation design.
• Prepare a field survey report as the basis for cable design, selection of cross‑sections and for acceptance after installation.

Operational warning: do not proceed with capacity upgrade if the survey shows the grid source or current connection method cannot meet operational conditions; in that case propose corrective measures or consult the distribution utility. Completion of the survey step is the basis for preparing the detailed technical dossier, price quotation and performing trial runs before handover.

Background: why the factory needs a capacity upgrade

The factory should upgrade the substation when measured peak load approaches or exceeds the rated capacity of the 250 kVA transformer, or when continuous operation requires additional headroom to move up to 630 kVA. ^[0][0]

Technically, common causes are load growth from production line expansion, adding ovens/boilers, compressors or HVAC systems; these increase peak demand and inrush currents during motor starts. Determining the correct upgraded size requires measured hourly/yearly load curves and parameters like power factor, diversity factor and engineering safety margin.

During maintenance shifts or site surveys, real‑world signals determine the option: frequency and duration of overloads, voltage drops at the point of supply, history of breaker trips, and the transformer’s insulation test results. Upgrades can be achieved by replacing with a larger transformer, adding a parallel transformer, or refurbishing MV/LV infrastructure and distribution panels; each option must be compared for losses, supply radius and operational reliability impact.

• Check actual metered load curves: determine hourly and annual peak demand.
• Inspect transformer condition: installation date, insulation condition, overload history and insulation test records.
• Record voltage dips or breaker trips during large starts (inrush) to assess required headroom.
• Cross‑check utility connection documents/acceptance records and coordinate survey, verification and acceptance before commercial energization.
• Assess the need for added surge protection, fire safety, protection panels and SCADA when the substation scale changes.

For technical decision‑making, the main criterion is comparing measured peak demand against the transformer rated capacity, including margins for starts and maintenance; if metering data is insufficient, perform load measurements and collect power factor data before finalizing the option. When moving to design and project preparation, work with the local utility/EVN for connection assessment, approval and acceptance.

Site survey: substation, medium‑voltage cable and metering

Reusing the existing Cu/XLPE/PVC 1x25mm2‑24kV underground cable is only feasible when documentation and field tests confirm ampacity, insulation condition and metering system are appropriate for the post‑upgrade capacity. ^[8][0]

Start surveys by reviewing documentation: as‑built drawings, initial acceptance records and cable/VT/CT datasheets if available. During maintenance shifts inspect the physical condition of the cable — sheath, terminations, cable trench, protective ducts and any signs of moisture or flooding.

Mandatory electrical tests include insulation resistance measurement with a Megger, loop impedance tests, phase/loop impedance and continuity checks of terminations. If insulation damage is suspected perform partial discharge testing or high‑voltage tests per professional procedures.

• Check utility/EVN acceptance records and cable/VT/CT datasheets; document all discrepancies in the field survey report (ohm measurements, insulation tests, photos).
• Visual inspection: sheath cracks, overheated/charred terminations, corrosion or partial discharge marks require intervention.
• Measure load current and power factor at the time of survey to compare with rated ampacity from datasheets and buried conditions.
• Assess actual ampacity according to installation conditions (single burial, cable grouping, ambient temperature); if ampacity is insufficient, replace cables or redistribute load.
• Check CT/VT and metering: determine accuracy class, current range and CT ratio suitable for post‑upgrade currents; if unsuitable, replace CTs or adjust metering scheme.
• Check grounding and lightning protection: measure earth resistance, verify armor/metal sheath bonding and the station lightning system condition.
• All measurements must be recorded in signed reports with calibration/certification of measuring instruments.

In the field, every technical finding must be documented with photos, location and measured values as the basis for deciding to reuse, refurbish or replace. After completing connection changes or capacity upgrade, schedule a load test, measure voltage regulation and monitor transformer temperature.

Operational warning: do not energize loads beyond cable or protection capacity without signed measurement reports and confirmation from the utility; any metering scheme changes must be accepted as per the current procedures.

Technical option: upgrade vs build new

Upgrading reuses the existing substation structure by replacing or extending the transformer, whereas building new installs a completely new substation on a new foundation with new equipment. ^[0][0]

From compliance and technical perspectives, the upgrade decision must start with verifying transformer acceptance records, insulation test reports, earth resistance results and CT/VT parameters. On site measure LV cable ampacity, check safety corridors, clearances and cooling capacity around the transformer; if any of these factors fail, building new is often the safer option.

Minimum field checklist includes:

• Transformer technical dossier and previous acceptance reports, insulation test results.
• Structural load capacity of foundation and panel frames (check bearing pressure, compartment dimensions).
• Ampacity of MV and LV cables, MV‑LV connection conditions and busbar capacity.
• Cooling/ventilation capacity, ventilation clearances and required cooling upgrades if needed.
• Protection system: relays, recloser, thermal relays, and coordination with the network protection.
• Measures to minimize supply interruption during transformer swap (outage scheduling, load transfer procedures).

Operational warning: do not increase capacity if cable ampacity or cooling capability has not been verified; during maintenance have a load test and switching plan to limit downtime. Procedurally, all capacity changes must be coordinated with the utility/EVN under the connection and acceptance process.

Light conclusion for the next step: when documentation and field checks allow it, upgrading is usually less costly than building new; if data is missing, structural or ampacity limits exist, switch to a new build option and prepare detailed acceptance and engineering calculations before execution.

Reusing existing medium‑voltage underground cable: checks and conditions

The 1×25 mm2 underground cable can only continue in service for a 630 kVA transformer if the ampacity adjusted for field conditions meets the expected load current and insulation plus terminations show no severe degradation; otherwise supplementation or replacement is mandatory. ^[16][17]

Field procedures must include conductor resistance measurement, insulation resistance (IR) before and after any intervention, joint inspection and mechanical inspection of the cable trench. During maintenance perform partial discharge (PD) testing if equipment is available and thermal monitoring during a trial run; all measurements should be compared with the original acceptance records.

• Document checks: route drawings, acceptance records, joint reports and field photos.
• Electrical tests: conductor resistance, IR before/after repair, PD survey if possible.
• Mechanical inspection: excavate suspect areas, observe insulation cracks, water ingress in the trench, corrosion of armor or sheath damage.
• Installation conditions: measure burial depth, distance to other ducts, number of parallel cables and ground/soil temperature influence.
• Grounding tests: check armor/metal sheath bonding and earthing of cable/station panels.

On‑site decision criteria must rely on measured results: rated ampacity must be corrected for burial conditions, grouping and soil temperature; if the adjusted ampacity is greater than or equal to expected load current and IR, PD, and joints are acceptable then reuse may continue with mitigation (temporary loading limits, thermal monitoring); if IR is significantly reduced or PD/joints show severe damage, prioritize cable replacement.

Operational warning: medium‑voltage joints are high‑risk points and must have joint records and contact resistance measurements; water in the trench, sheath cracks or PD detection are sufficient reasons to require immediate replacement. At acceptance and trial stages all capacity or connection changes must be notified to and accepted by the responsible EVN/distribution utility.

Action conclusion: perform IR, PD and thermal measurements during a load run, provide joint documentation and route drawings to the evaluator, and specify temporary measures or replacement based on measured results to reach a final decision.

Installing an outdoor 630kVA transformer on a foundation

The main requirements when replacing a transformer are to ensure foundation strength, earthing and clearance for cooling consistent with the new transformer’s size, weight and cooling method. In practice failing to verify required operating parameters and the actual mass can overload the foundation or hinder lifting operations. ^[3][2]

Before any execution collect the full spec sheet: rated power, HV/LV voltages, short‑circuit impedance (%Z), vector group, cooling type (ONAN/ONAF), weight, dimensions and lifting point locations. On site check foundation elevation, existing bearing capacity and surrounding density to determine if foundation reinforcement or repositioning is needed.

Field checks and acceptance criteria should include:

• Verify actual transformer weight and dimensions against foundation design; check concrete bearing capacity and any piles if present.
• Inspect oil containment trenches/ pits and oil containment measures to prevent spills for outdoor transformers.
• Measure earth resistance after earthing network installation linking transformer tank, foundation frame and busbars; retain acceptance records for coordination with EVN as required.
• Check safe clearances around the transformer for natural cooling and maintenance access, and confirm access for testing and repair works.

MV 22 kV and LV 0.4 kV connections must follow coordination with the utility/EVN regarding switching points, cable materials and safety clearances. During maintenance and acceptance have electrical test records and grounding confirmation from authorized acceptance bodies.

Practical warnings and decisions: do not position the transformer if the foundation has not been certified as structurally adequate; do not connect MV until approval or an approved cable routing plan is obtained from the utility/EVN. If there is doubt about cooling type (ONAN vs ONAF) or %Z parameters request the official manufacturer spec sheet and perform ambient temperature surveys at the location to ensure cooling matches manufacturer recommendations.

The next step for decision makers is to conduct a site survey, collect the full 630 kVA transformer spec sheet, and initiate utility acceptance coordination before designing the foundation and cable routes.

Reconfiguring the 24kV recloser 630A, LBFCO, CT/VT and metering

It is necessary to reconfigure the 24kV 630A recloser, adjust LBFCO/fuses, check or add CTs and review VTs, and recalibrate metering settings to ensure selectivity and regulatory compliance. ^[13][0]

To validate this requirement gather actual inputs: existing recloser functional acceptance records, short‑circuit diagrams at site, load characteristics after upgrade to 630 kVA and the present CT/VT connection diagram. On site, engineers must measure no‑load currents, identify CT/VT connection points and check LV cable ampacity before deciding to change LBFCO or CT ratios.

Work sequence with separate acceptance records for each step:

• Field survey and collection of recloser test records, circuit diagrams and load data.
• Check existing CT/VT: measure errors, insulation, overvoltage tolerance; assess whether VT 12kV/120V can be reused or must be replaced.
• Determine recloser settings (pickup, curve, time dial, reclosing count, lockout, earth‑fault pickup/time) for both main and backup scenarios.
• Adjust LBFCO/LV fuse sizes if needed based on cable ampacity and short‑circuit capacity; add CTs with appropriate ratios to cover the operating current range for protection and metering.
• Perform functional tests after adjustments: overcurrent, earth‑fault, reclosing, check RTU/SCADA and review event logs.
• Prepare acceptance records: recloser functional test, CT/VT verification and meter/measurement adjustment records per EVN procedures.

High‑level scope summary table:

Key technical decisions and operational warnings: choose CT ratios that cover the operating current range to avoid protection saturation or blind spots; LBFCO/fuse sizing must consider cable ampacity and fault current to avoid unnecessary trips. If VT is reused, provide verification of accuracy and insulation before connecting to metering circuits.

All changes must be documented with recloser functional test reports, CT/VT calibration reports and meter adjustment records; during maintenance preserve event logs and confirm RTU/SCADA before acceptance. To finalize settings and perform EVN acceptance studies, a full field survey and short‑circuit/load data collection is required.

Low‑voltage side: MCCB 1000A, protection relays, LV cables and 250kVAr capacitor bank

The MCCB 3P‑1000A is specified as the main LV breaker because it must withstand high inrush and fault currents after the upgrade; breaking capacity (Icu/Icw) must exceed the prospective fault current at the panel. On site measure the actual fault current after connection to confirm breaking capability and update protection parameters. ^[1][0]

Protection relays must provide overcurrent and earth‑fault functions with appropriate time‑current characteristics; use separate digital relays or MCCBs with integrated trip units, provided there are alarm contacts for SCADA and adjustable parameters. During site surveys verify that relays support phase unbalance functions and have alarm outputs for the monitoring system.

Select the LV cable 1×240 mm2 based on actual ampacity for the installation method (conduit or tray), grouping factors, temperature correction and conductor material. In maintenance or survey shifts it is mandatory to re‑measure voltage drop and check cable lengths to ensure allowable voltage drop and temperature limits are not exceeded.

The 250 kVAr capacitor bank is proposed to compensate reactive power and improve plant power factor; choose fixed or automatic switching type based on load distribution and cosφ targets. Required items for the capacitor bank include step switching controller, overcurrent protection for capacitors, fuses/breakers per capacitor step and voltage/phase protection; during acceptance measure cosφ before and after, measure delivered kVAr and check capacitor insulation.

• On‑site check: measure prospective fault current at the panel after the upgrade.
• On‑site check: verify cable ampacity according to installation and grouping factors.
• Acceptance tests: measure cosφ before/after, measure actual kVAr delivered by the capacitor bank and check system voltage drop.
• Operational warning: coordinate acceptance and connection with the local utility/EVN.

Light conclusion: equipment selection must rely on actual field measurements and coordination with EVN; the next reasonable step is to prepare a measurement list (hourly load profile, prospective fault current, cable lengths, ambient temperature) to finalize equipment specifications and protection settings.

Technical checks, acceptance testing and handover

Acceptance must confirm safe connections, compatibility of equipment after the capacity increase (250 → 630 kVA) and safe operation at energization. ^[0][0]

Before acceptance verify mechanical aspects, cable terminations and earthing; during maintenance or site survey measure insulation resistance, check insulating oil and mechanical fixings. Minimum checks to list for acceptance are:

• Mechanical checks: transformer positioning, anchoring, insulating oil condition (if oil replaced provide laboratory analysis report).
• Cable/termination and earthing checks: measure earth resistance, inspect joints, check lightning protection and temporary earthing during construction.
• Basic electrical tests: insulation resistance (Megger), winding resistance, CT/VT ratio checks if CT/VT changed, ratio and polarity tests.

Protection and control checks must include relay configuration, functional tests for overcurrent, earth‑fault, unbalance and coordination between relays and breakers. After energization prepare observation records of phase voltages, inrush currents, initial oil temperature and audible vibration/noise.

Acceptance documentation must include detailed test reports with results, energization record, construction log, factory certificates of equipment and as‑built connection diagrams. For connections to the distribution network follow the acceptance and energization procedures defined by the utility/EVN.

Operational warning: all acceptance records must specify responsibility for remediation, completion deadlines and whether the report is provisional or final; if testing data or factory certificates are missing do not perform official handover. To finalize acceptance collect full field survey data and detailed electrical test records before creating the handover report and maintenance logbook.