Core Functions of Distribution Substation

Core Functions of a Distribution Substation: What a 33/11 kV Substation Actually Does

Everything upstream of a distribution substation is engineered for bulk transfer. Everything downstream is a radial or lightly meshed network of 11 kV feeders, pole-top and kiosk transformers, and LV lines with very little real-time visibility. The 33/11 kV substation is the last place in the chain where the utility has full control of voltage, fault level, switching, and measurement in one location. That is why most customer-facing reliability problems (outages, low voltage, nuisance trips, high losses) either originate there or can be fixed there.

This guide breaks a distribution substation down into eight core functions, the equipment that delivers each one, the standards that govern it, and the calculations a practicing engineer needs to check a design or troubleshoot an existing site. The examples use a typical two-transformer 33/11 kV configuration of the kind found across DPDC, DESCO, BPDB, BREB/PBS, NESCO and WZPDCL networks.

What Is a Distribution Substation?

A distribution substation takes power delivered at sub-transmission voltage, steps it down to a primary distribution voltage, and divides it into protected, switchable feeders. In Bangladesh, the dominant arrangement is 33/11 kV, fed from a 132/33 kV grid substation, with 11 kV feeders running on to 11/0.4 kV distribution transformers.

The network is large and still growing. NESCO's published figures show 85 33/11 kV substations and 13,943 distribution transformers as of June 2025. Donor-funded modernisation programs are adding more: an AIIB-financed project for Rajshahi and Rangpur divisions covers 84 new and 32 augmented 33/11 kV substations (about 1,385 MVA), and a companion project for Chattogram and Sylhet covers roughly 2,062 MVA of 33/11 kV capacity plus SCADA and river-crossing works. In Dhaka, where land is scarce, DPDC has begun installing high-capacity 35/50 MVA 33/11 kV power transformers.

Table 1: Substation Types by Function and Voltage (Bangladesh Context)

Type	Typical Voltage Ratio	Role	Typical Owner/Operator
Grid substation	230/132 kV, 132/33 kV	Bulk step-down, system control	PGCB (and distribution-company-owned 132/33 kV in some cities)
Distribution substation	33/11 kV	Primary distribution: transform, switch, protect, regulate	DPDC, DESCO, BPDB, BREB/PBS, NESCO, WZPDCL
Switching substation	33 kV or 11 kV	Sectionalising and load transfer, no transformation	Distribution utilities
Distribution transformer station	11/0.4 kV	Final step-down to LV	Distribution utilities

The Eight Core Functions at a Glance

The single-line diagram below shows a typical split-bus layout. The numbered gold callouts map to the eight functions covered in the sections that follow.

Table 2: Function-to-Equipment Map

#	Function	Primary Equipment	Governing Standards (verified current editions)	What Fails If Neglected
1	Voltage transformation	Power transformer, Dyn11, ONAN/ONAF	IEC 60076-1:2011 (Ed. 3.0); IEEE C57.12.00-2021	Overheating, insulation ageing, unplanned outage
2	Distribution and switching	MV switchgear, busbars, bus-section CB	IEC 62271-200:2021 + AMD1:2024; IEC 62271-100:2021 (circuit-breakers)	Wrong fault level, loss of supply to whole bus
3	Protection	Relays, CTs/VTs, circuit breakers	IEC 60255 series; IEEE C37.2 device numbers	Slow clearing, equipment damage, wider outages
4	Voltage regulation	OLTC, AVR relay	IEC 60076-1 (tap-changer provisions)	Low/high consumer voltage, tap-changer hunting
5	Reactive power control	Capacitor bank, detuning reactors	IEC 60871/60831 family (verify edition)	Poor power factor, feeder losses, voltage drop
6	Monitoring, control, metering	RTU, bay controllers, SCADA	IEC 61850 series (verify part editions)	Blind operation, slow fault location
7	Earthing and safety	Earth grid, NER, earthing transformer	IEC 61936-1:2021; IEEE 80 (verify current edition)	Dangerous touch/step voltage, relay misoperation
8	Auxiliary supply	110 V DC system, battery, station service transformer	IEC 61936-1:2021	Protection cannot trip, breakers cannot operate

Function 1: Voltage Transformation

The 33/11 kV power transformer is the core of the substation and its highest single cost. A common specification is 20/26 MVA ONAN/ONAF, Dyn11, with an on-load tap changer (OLTC) on the 33 kV winding, although ratings vary by utility and site (Dhaka's newer 35/50 MVA units are one example).

Why Dyn11 is widely specified: the delta on the 33 kV side traps zero-sequence currents and third harmonics, and the star point on the 11 kV side is available for neutral earthing (Function 7).

Worked Example 1: Full-Load Current

For a transformer rated 20 MVA (ONAN) and 26 MVA (ONAF):

I = S / (√3 × V)

33 kV side:  I(20 MVA) = 20,000 / (1.732 × 33) = 350 A
             I(26 MVA) = 26,000 / (1.732 × 33) = 455 A

11 kV side:  I(20 MVA) = 20,000 / (1.732 × 11) = 1,050 A
             I(26 MVA) = 26,000 / (1.732 × 11) = 1,365 A

These four numbers set CT ratios, incomer relay pickup, cable ampacity and busbar ratings. The 11 kV incomer relay must pick up above 1,365 A (the ONAF rating) or it will trip the transformer during legitimate fan-assisted loading.

Design checks for the transformer:

• Rating plate data, tolerances, temperature-rise limits and test requirements follow IEC 60076-1:2011, or IEEE C57.12.00-2021 where a tender specifies the IEEE route. Confirm which family the tender references; mixing them in one specification is a common source of disputes.
• Ambient design temperature matters in Bangladesh. Summer ambient plus enclosed-room heat raises winding and oil temperatures; check the rating at actual site conditions, not only at the standard 30 °C reference (see the loading guide IEC 60076-7, verify current edition).
• Specify Buchholz relay, winding and oil temperature indicators, pressure relief device, and oil-level gauge. These feed Function 3.

Function 2: Distribution and Switching

Below the transformer, the 11 kV switchboard splits power into individually controlled feeders. Its job is to connect, isolate and sectionalise circuits safely, and to make the substation operationally flexible.

Busbar scheme. The layout in Fig. 2 uses two buses joined by a normally open bus-section circuit breaker. In normal operation, each transformer feeds its own bus. When one transformer is out of service, the bus-section breaker closes, and the remaining unit supplies both buses. Operating split limits fault level and keeps a bus fault from taking down the whole substation.

Switchgear standard. Indoor 11 kV metal-enclosed switchgear is covered by IEC 62271-200:2021 (Ed. 3.0), amended by AMD1:2024 (consolidated as Ed. 3.1). It applies to AC switchgear above 1 kV up to and including 52 kV. Two classifications drive purchasing decisions:

• Loss of service continuity (LSC): how much of the board remains live when one compartment is opened.
• Internal arc classification (IAC): the board's tested ability to protect personnel during an internal arc fault. The 2021 edition moved internal-arc testing of pole-mounted switchgear out to IEC 62271-214:2019, so IAC for pole-mounted gear is not covered in -200 anymore.

Circuit breakers are covered by IEC 62271-100:2021, and the common specifications for all HV switchgear by IEC 62271-1:2017 with Amendment 1:2021. For the isolator and earthing-switch operating sequences that apply on these boards, see our separate article on HV isolator phase connect/disconnect sequences (IEC 62271-102, IEEE C37.30.1).

GIS versus AIS. In Dhaka, where land is the binding constraint, gas-insulated and underground substations are becoming common. Project documents for DPDC's expansion programs list 33 kV and 11 kV GIS and gas-insulated transformers (reported as 33/11 kV, 50 MVA units). Outside the city, air-insulated outdoor 33 kV yards remain the norm at rural BREB/PBS sites. Choose on land cost, flood risk, maintenance skills and humidity exposure rather than on first cost alone.

Worked Example 2: Fault Level at the 11 kV Bus

Assume a 20 MVA transformer with 10% impedance (on its own base) and a very strong 33 kV source (infinite-bus assumption, which gives a conservative upper bound):

Isc (one transformer)   = S / (√3 × V × Z)
                        = 20 / (1.732 × 11 × 0.10)
                        = 10.5 kA

Isc (two in parallel)   = 2 × 10.5 = 21.0 kA   (bus-section CB closed)

This is the reason for running a split-bus. With the coupler closed, the available fault current doubles, and switchgear selected for a split-bus duty (for example, 25 kA, 3 s, one of the commonly specified ratings) may be pushed close to its limit once real source impedance, cable contribution and motor feedback are considered. Always confirm with a full short-circuit study to IEC 60909 (verify current edition) rather than this shortcut.

Function 3: Protection

Protection detects a fault, decides which breaker must open, and clears it quickly enough to limit damage while keeping the healthy network energised.

Table 3: Protection Functions in a Typical 33/11 kV Substation

Device No. (IEEE C37.2)	Function	Protects	Typical Action
50/51	Instantaneous / time-overcurrent	Feeders, incomers, transformer back-up	Trip feeder or incomer CB
50N/51N	Earth-fault overcurrent	Feeders, incomers	Trip, sensitivity set by NER current
87T	Transformer differential	Transformer windings and terminals	Trip both CBs, lockout (86)
63 (Buchholz, pressure)	Gas/oil surge	Transformer internal faults	Alarm or trip
49	Thermal overload	Transformer winding temperature	Alarm, then trip
50BF	Breaker failure	Stuck breaker	Trip upstream breakers
27/59/81	Under/over-voltage, frequency	Bus voltage, load-shedding	Alarm, shed feeders
86	Lockout	Prevents reclosing after serious faults	Manual reset required

Inverse-Time Overcurrent: The Formula

IEC-curve relays calculate operating time from the fault current multiple:

t = TMS × k / [ (I / Is)^α − 1 ]

Standard inverse (SI):   k = 0.14,  α = 0.02
Very inverse (VI):       k = 13.5,  α = 1.0
Extremely inverse (EI):  k = 80,    α = 2.0

Where I is fault current, Is is the pickup setting and TMS is the time multiplier setting. The curve family is defined in the IEC 60255 relay standards (check the current edition of IEC 60255-151 before quoting clauses in a protection study).

Worked Example 3: Grading a Feeder Against the Incomer

Settings used in Fig. 4:

Relay	Pickup Is	TMS	Curve
11 kV feeder	400 A	0.10	SI
11 kV incomer	1,400 A (just above 1,365 A ONAF load)	0.20	SI

Fault at 4.0 kA:
  Feeder:  t = 0.10 × 0.14 / ((4000/400)^0.02 − 1)  = 0.297 s
  Incomer: t = 0.20 × 0.14 / ((4000/1400)^0.02 − 1) = 1.32 s
  Margin  Δt = 1.02 s

Fault at 10.5 kA (maximum, one transformer):
  Feeder:  t = 0.207 s
  Incomer: t = 0.681 s
  Margin  Δt = 0.47 s

The required grading margin covers circuit-breaker opening time, relay overshoot, CT errors and a safety allowance. A margin of roughly 0.3 to 0.4 s is a common planning target for electromechanical-era practice; digital relays with fast breakers can justify a tighter figure if the utility's standard allows it. Notice that the margin shrinks from 1.02 s to 0.47 s as fault current rises, because both curves flatten at high multiples of pickup. That shrinkage is a design signal: add an instantaneous (50) element on the feeder, or move the incomer to definite-time, to preserve selectivity at the top of the fault range.

Practical checks:

• CT saturation at 10 kA or more can delay or distort relay operation. Verify the CT knee-point voltage and burden for the highest fault level.
• Protection depends entirely on the DC supply (Function 8). A relay without a healthy battery cannot trip anything.
• Settings must be re-verified whenever transformer ratings, source impedance or feeder configuration changes (for example, after a capacity augmentation).

Function 4: Voltage Regulation

As load rises, the feeder voltage drops. The OLTC on the transformer shifts the turns ratio under load so the 11 kV bus stays within the utility's voltage band.

How it works. A typical 33 kV-side OLTC provides about ±10% range in 1.25% steps (commonly 17 positions). An automatic voltage regulator (AVR relay, device 90) compares bus voltage to a setpoint and issues raise/lower commands to the tap-changer motor drive.

Voltage change per tap step at 11 kV = 1.25% × 11,000 V = 137.5 V

Settings that matter:

• Bandwidth (dead-band): must be wider than one tap step, otherwise the OLTC hunts continuously and wears the diverter switch.
• Time delay: long enough to ignore transient dips from motor starting or fault clearing.
• Line-drop compensation (LDC): raises the bus setpoint as load current increases, so voltage at the feeder's far end stays acceptable.
• Parallel operation: two transformers on one bus need a master/follower or circulating-current scheme, or the taps drift apart and circulate reactive current.

Worked Example 4: Why Regulation and PF Correction Work Together

Feeder voltage drop (approximate):

ΔV (%) = 100 × (P·R + Q·X) / V²      [P in MW, Q in MVAr, R and X in Ω, V in kV]

An 11 kV feeder carries 5 MW at 0.90 power factor (Q = 2.42 MVAr), with R = 1.2 Ω and X = 1.0 Ω:

Before correction:  ΔV = 100 × (5×1.2 + 2.42×1.0) / 121 = 6.94 %
After pf → 0.98 :   Q = 5 × tan(acos 0.98) = 1.02 MVAr
                    ΔV = 100 × (5×1.2 + 1.02×1.0) / 121 = 5.80 %

Correcting power factor recovers more than one percentage point of voltage without touching the tap-changer. It also cuts I²R loss on the feeder.

Function 5: Reactive Power Control

Inductive loads (motors, transformers, air-conditioning compressors) draw reactive power that travels back through the entire network. Capacitor banks on the 11 kV bus supply it locally.

Worked Example 5: Capacitor Bank Sizing

A bus serving 15 MW at 0.90 power factor needs correcting to 0.98:

Qc = P × (tan φ1 − tan φ2)
   = 15 × (tan(acos 0.90) − tan(acos 0.98))
   = 15 × (0.4843 − 0.2031)
   = 4.22 MVAr

A bank of about 4.5 MVAr in three switched steps gives sensible control.

Design cautions:

• Harmonics. Rectifier-heavy loads (VFDs, LED drivers, UPS) can trigger resonance with a plain capacitor bank. Where harmonic distortion is present, use detuning reactors, commonly specified at about 7% (confirm with a harmonic study, not a rule of thumb).
• Switching transients. Back-to-back switching of banks creates high inrush; use inrush-limiting reactors or controlled switching.
• Stored energy. A bank holds charge after disconnection. Discharge devices and a verified discharge time are a safety requirement, not an option.

Function 6: Monitoring, Control, Metering and SCADA

Modern substations are measured and controlled remotely. Bay controllers or protection relays collect currents, voltages, breaker status and alarms, and an RTU or gateway forwards them to the control centre.

• IEC 61850 is the dominant substation communication standard, defining data models, GOOSE messaging for fast inter-relay signals, and a common engineering language across vendors. The series has been updated in parts, so verify the specific part and edition named in each tender.
• Telecontrol protocols such as IEC 60870-5-104 and DNP3 remain common between substations and control centres, particularly where legacy systems are integrated.
• Revenue and operational metering at incomers and feeders gives the energy balance that identifies technical and commercial losses.

SCADA is now written into Bangladesh's distribution upgrade programs. DPDC's expansion project includes a central SCADA system alongside underground cables and new substations, and the AIIB-financed Chattogram/Sylhet project lists SCADA and switching stations in its scope. The practical benefits: faster fault location, remote switching to restore supply, load-profile data for planning, and automatic feeder reconfiguration (FLISR) where the network topology allows it.

Function 7: Earthing and Safety

Earthing does three jobs at once: it carries fault current into the ground, limits touch and step voltages to safe values, and defines how the network behaves during earth faults.

Neutral earthing. A transformer with a delta winding on one side and no accessible 11 kV neutral needs an earthing (zig-zag) transformer to create one. A neutral earthing resistor (NER) then limits earth-fault current to a chosen value.

Worked Example 6: NER Sizing

To limit the earth-fault current to 300 A on an 11 kV system (an illustrative value; confirm the utility's own earth-fault standard, as practice varies):

R = Vphase / If = (11,000 / √3) / 300 = 6,351 / 300 = 21.2 Ω

Limiting to 1,000 A would need 6.35 Ω. A lower current reduces damage and ground potential rise, but protection must still detect it, so relay sensitivity (50N/51N) is set around the NER current.

Earth grid design. Design and test the earth grid to IEEE 80 (verify the current edition) and IEC 61936-1:2021, which covers power installations above 1 kV AC including earthing requirements. Soil resistivity in Bangladesh's alluvial and coastal areas changes strongly with season, so design with wet- and dry-season measurements. For low-cost enhancement methods and their limits, see our earlier article on earthing with salt and charcoal.

Function 8: Auxiliary Supply

The protection, control and breaker-operating circuits run from a 110 V DC system (some utilities use 48 V or 220 V) backed by a battery bank, charged from the 415 V station service supply.

Worked Example 7: Battery Sizing (Simplified)

Continuous load:   8 A for 8 h                      = 64.0 Ah
Momentary load:    40 A for 1 min (trip + close)    =  0.7 Ah
Subtotal                                            = 64.7 Ah
× ageing factor 1.25                                = 80.9 Ah
× design/temperature margin 1.1                     = 89.0 Ah
Selected standard size                              = 100 Ah

This is a simplified screening calculation. Final sizing should follow the manufacturer's discharge tables and a recognised method such as the IEEE 485 approach for lead-acid cells. Add earth-fault monitoring on the DC system, a low-voltage alarm, and a duty-cycle test during commissioning.

Cross-Cutting Requirement: Reliability and N-1 Planning

A two-transformer substation is only as reliable as its planning rule. Firm capacity is the load the substation can carry with its largest transformer out of service. For the 2 × 20/26 MVA example, firm capacity is 26 MVA (one unit at its ONAF rating), not the 52 MVA installed.

In the illustrative profile above, the evening peak of 24.8 MVA is 95% of firm capacity. The substation looks lightly used on paper (48% of installed MVA at peak) yet has almost no headroom for a transformer outage. Short-term overload capability, defined in the loading guides, can cover brief gaps, but new connections should trigger a capacity review long before the peak reaches the firm limit.

This is where Dhaka's experience is instructive. Press reports have highlighted that customer numbers grew far faster than transformer and substation capacity in earlier years, which is exactly the situation N-1 planning is meant to prevent.

Bangladesh-specific reliability factors:

• Humidity and monsoon: condensation and tracking in indoor switchrooms. Specify anti-condensation heaters, adequate ventilation and sealed cable entries.
• Flooding: raise plinths, protect basement and underground substations, and keep cable trenches drained.
• Heat: derate equipment at actual enclosure temperatures. The same logic applies to breakers; see our article on circuit breaker tripping problems for the ambient derating method.
• Cable feeders: 11 kV cable sizing is covered separately (IEC 60502-2, with IEC 60949 for short-circuit withstand).

Emerging Role: Rooftop Solar and Reverse Power Flow

The Net Metering Guideline 2025 allows rooftop systems up to 100% of sanctioned load and opens net metering to single-phase consumers, and a December 2025 Power Division circular made rooftop solar mandatory for qualifying new connections. As this capacity builds up on 11 kV feeders, a substation that was designed for one-way flow starts to see power moving back toward the transformer at midday.

Engineering consequences to plan for now:

• Protection: directional overcurrent elements and re-checked grading, because fault current may flow from the feeder side.
• Voltage regulation: midday overvoltage at the feeder end; AVR and LDC settings tuned for load-only assumptions can misbehave.
• Metering: bidirectional energy measurement at feeder level for loss analysis.

For the national policy picture behind this shift, see our article on the future of renewable energy in Bangladesh to 2041.

Risk and Safety Instructions

Substation work combines high energy, stored energy and limited access. Treat the following as minimum requirements, subject to the utility's own safety rules and permit system.

• Isolate, prove dead, earth. Use the utility's permit-to-work and lock-out/tag-out procedure. Verify isolation with an approved voltage detector, then apply earths at the work location. Never rely on breaker position indication alone.
• Never defeat interlocks. Interlocks between isolators, earthing switches and breakers exist to prevent operation under load or on live parts.
• Arc-flash. Assess incident energy before any live work, using the method in IEEE 1584 (verify current edition). Use arc-rated PPE matched to the calculated energy. Prefer IAC-classified switchgear and remote racking.
• CT secondaries. Never open a live CT secondary circuit. The resulting voltage can be lethal and can destroy the CT. Short the secondary first.
• Capacitor banks. Wait for the specified discharge time and verify with a meter, then apply the discharge/earthing stick.
• SF6 equipment. Follow gas-handling procedures, ventilate low-lying GIS rooms, and use trained personnel for gas work. Decomposition by-products are toxic.
• Battery rooms. Lead-acid cells release hydrogen when charging. Keep ignition sources out, ventilate, and wear eye and face protection.
• Transformer oil. Provide soak pits, oil containment and fire separation between transformers. Treat any gas-relay trip as a possible internal fault: no re-energisation until diagnosed.
• Touch and step voltage. Do not assume the earth grid is adequate after modifications; re-test after any extension, and use insulating mats or equipotential bonding at operating positions.
• Fault level changes. Re-run short-circuit studies after any change in source, transformer rating or bus configuration, and confirm breaker making and breaking duties.

Quick-Reference Decision Matrix

Operational Problem	Function Involved	First Check	Standard / Method
Consumers report low voltage at feeder end	4, 5	AVR setpoint, LDC, power factor, tap position	Voltage-drop calc; capacitor sizing
Entire bus trips for a feeder fault	3	Grading margin, breaker failure, relay settings	IDMT calc; coordination study
Transformer hot on summer evenings	1, N-1	Loading vs ONAF rating, ambient, cooling operation	IEC 60076-1; IEC 60076-7
Switchgear nearing fault-level limit	2	Bus-section status, new source contribution	IEC 60909 study; IEC 62271-200 ratings
Relays fail to trip on test	8, 3	Battery voltage, DC earth fault, trip coil circuit	DC system test
Earth faults not detected	7, 3	NER value, 50N/51N pickup, CT ratio	R = V/(√3·If)
Reverse flow at midday	3, 4, 6	Directional elements, AVR behaviour, metering	Net metering interconnection study
Cannot locate faults quickly	6	RTU/SCADA coverage, fault indicators, event logs	IEC 61850 / telecontrol

Conclusion

A distribution substation is not just a transformer in a fenced yard. It is eight functions working together: transform the voltage, switch and sectionalise the load, clear faults selectively, hold voltage inside limits, supply reactive power, report what is happening, keep people safe through earthing, and keep the control system alive with a healthy DC supply. Weakness in any one of them shows up as an outage, a voltage complaint or an accident somewhere else in the network.

For engineers working on Bangladesh's expanding 33/11 kV network, the practical priorities are consistent: plan on firm (N-1) capacity rather than installed MVA, grade protection against the real fault level at the bus, verify each standard's current edition in the tender documents, and design for humidity, heat and flooding from the start. With rooftop solar and SCADA both scaling up, the substations built and upgraded in the next few years will need to handle two-way power flow and remote operation from day one.

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Have you worked on a 33/11 kV substation upgrade, a protection grading study or an OLTC voltage-regulation problem in Bangladesh? Share your experience in the comments. WAZIPOINT is building out a technical reference series on substation equipment and protection for South Asian field conditions.