Substation maintenance for factories

Overview of substation maintenance tasks in a factory

Substation maintenance includes visual inspections, routine servicing, periodic testing, fault repairs, major overhauls and condition monitoring. ^[8][2]

For substations located inside a factory, these items should have clear responsibility split between the owner and contractors, and the plan must be based on operation history and environmental conditions.

On-site visual inspections focus on enclosures, flooring, ventilation systems, signage and safety clearances.

During a site survey on an inspection shift, check circuit breakers, bay compartments, cable terminations, oil stains and signs of SF6 leaks (if present), and photograph the site for records.

Typical routine servicing tasks include tightening connections, cleaning insulation, lubricating contacts, replacing oil filters/cylinders and checking cooling systems.

Operational mechanisms should be calibrated after servicing and operation logs recorded to monitor the effectiveness of interventions in subsequent shifts.

Periodic testing includes oil analysis (DGA, moisture, acidity), insulation testing (tanδ), winding resistance measurement and short‑circuit impedance tests.

During acceptance/inspection shifts, protection relay testing and metering checks must be performed and results stored for trend comparison and as the basis for further actions.

• Quick inspections: daily/weekly depending on operating conditions.
• Basic servicing: typically every 6–12 months, depending on loading and environment.
• In‑depth testing: annually or every 3–5 years depending on test type and operating conditions.
• Major overhaul: based on accumulated operating hours or condition analysis.

Responsibilities must be clearly allocated: the owner prepares the maintenance plan, ensures technical documentation, safety and coordination with the distribution utility when required.

The contractor/maintenance provider is responsible for carrying out technical work, providing work records, test results, site photos and proposing specific remedial actions.

Safety procedures during maintenance must include permit‑to‑work, energy isolation, signage and exclusion zones, hot‑work/explosion monitoring and verification of grounding before work starts.

After work, mandatory documentation includes the work report, test results, operation logs, list of replaced parts, site photos and an acceptance report to ensure thorough repairs.

Repair vs replacement decisions are based on damage severity (oil leaks, insulation loss, winding deformation), DGA/oil analysis results, equipment age and life‑cycle cost.

Prioritize remote monitoring for oil parameters, temperature and fault current where SCADA/remote measurement is available, to shift from time‑based maintenance to condition‑based maintenance.

A detailed field survey is required to define scope, frequency and acceptance requirements appropriate to operating conditions.

Field documentation and incident history determine intervention priority and resources needed for the next maintenance campaign.

Transformer maintenance details: oil, DGA, mechanical checks

A periodic DGA program is required, with correct sampling points and oil handling according to results, accompanied by mechanical inspections. ^[14][13]

On site, mark sampling locations, record temperature and operating condition at the time of sampling.

DGA testing frequency should be classified by transformer condition: new, suspect or previously abnormal.

Oil parameters to monitor include principal dissolved gases, moisture, acid number, conductivity and breakdown voltage, as listed below.

Sampling procedures must take from the sample valve or oil tank, avoid contamination and ensure safe conditions.

Record field information including equipment ID, oil temperature, load state and sampler before sealing the sample.

Before filtering or replacing oil, check basic contamination, leaks and compare oil quality with reference samples.

The decision to filter or fully replace oil depends on contamination level and DGA results; it cannot be based on a single parameter alone.

When abnormal DGA results are found, isolate the unit, increase monitoring frequency and perform additional electrical tests before further measures.

Mechanical checks include seals, terminal bolts, insulating enclosures, oil valves and cooling systems, performed per manufacturer specifications.

Tightening and contact inspections should be done during maintenance shifts and marked after torqueing to monitor subsequent movement.

Use thermal imaging and vibration analysis to implement condition‑based maintenance, reducing unnecessary periodic tasks at the substation.

Repair or replacement criteria are based on core/winding damage, signs of arcing or overheating from DGA and insulation degradation.

When detailed assessment is required, carry out a field survey and prepare a cost‑and‑risk report before decision.

The above steps form the basis to decide a condition‑based maintenance strategy or to proceed with major repairs when needed.

Fault detection methods: thermography, PD, DGA

Thermography is used to detect hot spots from poor contact or high resistance; PD measurement detects insulation faults; and DGA applies to oil‑filled transformers when internal overheating is suspected. ^[1][15]

On site, thermographic scans should be performed both when equipment is energized and outside operating hours, prioritizing connections, cable ends, lugs, busbars and relay contacts; combine visual observation and listening for abnormal sounds. This method is sensitive to temperature rises from poor contacts and resistance heating but cannot detect small internal PD inside insulation.

Partial discharge (PD) measurement uses specialized equipment such as ultrasonic sensors, TEV probes or systems to IEC 60270; when surveying a factory site, surface corona and external noise must be excluded before conclusions. During maintenance, PD measurement is performed after suspect operations or repairs and trends over time should be observed rather than single values.

DGA (dissolved gas analysis) is applied to oil‑filled transformers when internal overheating, micro‑fires or for establishing an oil CBM program; analysis focuses on ratios and trends of gases such as H2, CO, CH4, C2H2. Sampling must be from correct points, avoid contamination, and record temperature and operation history; if in‑house analysis is not available, send to a qualified lab or use a calibrated GC device.

• CBM/CBT frequency: thermography periodically (e.g., monthly or per equipment risk),
• PD: condition‑based (after anomaly detection, after repairs) or annually for critical equipment,
• DGA: baseline sample and periodic monitoring, typically every 6–12 months, increasing frequency when abnormal indicators appear.

Action priorities: major hot spots must be addressed immediately; high or rapidly increasing PD requires isolation and investigation; DGA indicating arcing (rising C2H2) needs detailed inspection and emergency repair planning. Always prioritize time‑trend comparisons rather than conclusions from a single sample.

Operational warnings: thermography can be affected by high load or ambient conditions, PD measurement requires a controlled measurement environment and noise control, DGA may reflect past events because gases dissolve slowly into oil. When surveying a factory, comply with operational safety rules and verify findings before technical intervention.

Regulatory requirements, acceptance records and storage

Ministerial documents from the Ministry of Industry and Trade, EVN guidance and circulars on connection/metering form the primary legal framework to follow when performing maintenance, repairs and acceptance of substations. ^[5][14]

On site, acceptance records are prerequisites for handover and commissioning; during maintenance shifts check records before re‑energizing according to distribution utility/EVN rules.

Typical components of post‑maintenance/testing acceptance records include:

• Work report (detailing scope, time and personnel involved).
• Test reports / test certificates related to the serviced equipment.
• Work logs and measurement session logs, if any.
• Safety acceptance report and handover to operations.
• Asset and construction handover documentation: approved design files, final acceptance records, and estimates/settlements when changes from the original design exist.

When surveying on site, verify completeness of test certificates (equipment name, results, signatures and the executing organization’s stamp) and match equipment IDs/tags with handover records.

Procedurally, acceptance records are usually submitted to the distribution utility/EVN before re‑energizing or official commissioning, per conditions in the connection/metering circular; exact deadlines and submission procedures depend on the specific circular and EVN guidance.

Conditions requiring independent testing typically include:

• When law or the circular mandates independent testing.
• When the investor or EVN requests independent verification of measurements/assessments.
• When technical disputes arise or defects are found that may affect operational safety.

The owner/customer is responsible for preparing a complete record package, notifying acceptance timing, coordinating with the distribution utility during acceptance and ensuring record validity per legal requirements; during acceptance keep a valid handover report and acceptance log.

Operational warning: do not re‑energize or hand over to operations when mandatory acceptance records are incomplete or when independent test results (if required) are pending confirmation; in practice this often leads to legal liability and safety risks.

If you need to determine mandatory records and submission deadlines for a specific case, conduct a site survey and cross‑check EVN guidance and the connection/metering circular to define next steps.