Introduction

FALSE. Interconnection increases the short-circuit MVA (SCMVA) of the buses that are connected.

Justification

• The short-circuit MVA at a bus is

$$SCMVA = \frac{MVA_{base}}{Z_{th}\ (\text{pu})}$$

where $Z_{th}$ is the Thevenin impedance seen from the faulted bus.

• When a bus is tied to another system, the second system's generators feed the fault through the tie line. The tie path is in parallel with the existing source impedance, so $Z_{th}$ becomes smaller.
• Smaller $Z_{th}$ means larger fault current and larger SCMVA.

Example: a bus with $Z_{th} = 0.2$ pu (100 MVA base) has SCMVA $= 500$ MVA. If an interconnection adds a parallel path of $0.3$ pu, then $Z_{th} = (0.2 \times 0.3)/(0.5) = 0.12$ pu and SCMVA $= 833$ MVA.

Consequences

• Circuit breakers and switchgear at the connected buses may need higher breaking capacity.
• A higher SCMVA is also good: the bus becomes a "stiffer" source, so voltage dips and flicker during load changes are smaller.
• Fault levels can be limited by series reactors, high-impedance transformers or HVDC links (which do not add fault current).

An interconnected system is one in which several generating stations and regional networks are tied together by transmission lines so that they work as one grid (for example the Integrated Nepal Power System, INPS, and its links with India).

Advantages

1. Higher reliability: if one plant trips, others supply the load through the ties.
2. Lower reserve capacity: spinning and standby reserve is shared, so total installed reserve is reduced.
3. Economic dispatch: cheapest plants (e.g. run-of-river hydro in the wet season) can be used fully; costly plants run less.
4. Use of load diversity: peaks of different regions occur at different times, so the combined peak is lower than the sum of peaks.
5. Larger, more efficient units can be installed because a single unit is a small part of the total.
6. Energy exchange/trade: surplus energy can be exported (e.g. Nepal to India in the monsoon) and deficits imported in the dry season.
7. Better frequency and voltage regulation because the grid is "stiffer".

Disadvantages

1. Higher fault level (SCMVA), so breakers of higher rating are needed.
2. Cascading failure: a disturbance in one area can spread and cause a wide-area blackout.
3. Complex operation: load-frequency control, tie-line scheduling and protection coordination are harder.
4. Stability problems: inter-area oscillations and transient stability limits on long ties.
5. High capital cost of tie lines and communication/SCADA systems.

Need of transmission system planning

Transmission planning decides what lines and substations to build, where, at what voltage and when, so that future generation can reach future load reliably and at least cost. It is needed because:

• Load growth: demand grows every year; the network must be expanded before it becomes overloaded.
• New generation: hydro sites in Nepal are far from load centres, so evacuation lines must be planned with the projects.
• Long lead time: lines take 5–10 years (survey, right-of-way, financing, construction).
• Economy: correct choice of voltage level, number of circuits and route minimises total cost (capital + losses).
• Reliability criteria: the grid should withstand single contingency (N-1) outages.
• Technical limits: thermal, voltage-drop and stability limits must be met for all future years.
• Coordination: with distribution planning, cross-border trade and environmental/right-of-way constraints.

TRUE.

• Transmission lines use large conductors (low resistance per km) and large phase spacing (higher inductance), so $X \gg R$. Typical $X/R$ is about 5–10 for 132–220 kV lines and 10–20 or more for EHV lines with bundled conductors.
• Distribution lines (11 kV, 400 V) use small conductors with close spacing, so $R$ is comparable to or larger than $X$; $X/R$ is about 0.5–2.

Consequences: in transmission lines voltage drop depends mainly on reactive power ($\Delta V \approx QX/V$) and power flow on angle, while in distribution feeders voltage drop depends strongly on real power ($\Delta V \approx (PR+QX)/V$), and $I^2R$ loss is a major concern.

Both HVAC and HVDC are used for bulk power transfer. HVAC is the normal choice; HVDC becomes better for very long distances, submarine cables and asynchronous links.

Technical comparison

Economic comparison

• Line cost: HVDC line is cheaper: fewer conductors, smaller towers, narrower right-of-way, less insulation (peak = working voltage).
• Terminal cost: HVDC needs costly converter stations, filters, smoothing reactors and reactive support; HVAC terminals (transformers, switchgear) are cheaper.
• Losses: HVDC has lower line loss (no skin effect, less corona, no reactive current).
• Break-even distance: total cost lines cross at about 500–800 km for overhead lines and 30–50 km for underground/submarine cables. Below this HVAC is cheaper; above it HVDC is cheaper.

 Cost
  |          AC total
  |         /
  |        /   DC total
  |       /  _/
  |      / _/
  |  DC_/_/   <- DC terminal cost
  | _/ /
  |/ /  AC terminal cost
  +----|-------------------> Distance
     break-even (500-800 km)

Conclusion of comparison: HVAC suits short and medium distances and meshed grids with many tap points; HVDC suits long-distance bulk transfer, cables, and asynchronous interconnections.

TRUE.

• Line-commutated (thyristor) converters always draw current that lags the voltage, both as rectifier (firing angle $\alpha$) and as inverter (extinction angle $\gamma$), plus extra lag due to commutation overlap $\mu$.
• The reactive power consumed is roughly $Q \approx P\tan\phi$ with $\cos\phi \approx \frac{1}{2}[\cos\alpha + \cos(\alpha+\mu)]$; in practice $Q$ is 50–60% of the transmitted real power at each end.
• This reactive power is supplied by AC filters (which also remove harmonics), shunt capacitor banks, synchronous condensers or SVC/STATCOM at the converter station.

So a 1000 MW HVDC terminal needs about 500–600 MVAr of local reactive support. (Voltage-source converter HVDC does not have this need, but the statement refers to conventional HVDC.)

TRUE (in general).

• In a large grid the total inertia ($\sum H$) of all connected machines is large, so a sudden load change or loss of a generator causes only a small change in frequency.
• The grid's low Thevenin impedance (high SCMVA) keeps bus voltages steady during disturbances; it acts like an "infinite bus" for each small plant.
• Spinning reserve is shared, so other plants pick up the load of a tripped unit.
• An isolated system has small inertia and little reserve, so frequency and voltage swing much more and it can collapse after losing one unit.

Limitation: very long weak ties may create inter-area oscillations and a fault can cascade, so a grid is more stable only when it is properly planned, protected and controlled.

TRUE.

• No stability limit: AC power transfer $P = \frac{V_s V_r}{X}\sin\delta$ falls as line reactance $X$ grows with length; HVDC has no reactance in steady state, so it has no length-based stability limit.
• No charging current and no need for intermediate compensation on long lines.
• Lower line cost and loss: two conductors instead of three, smaller towers, narrower corridor, no skin effect and lower corona loss.
• Economics: HVDC terminal stations are costly, but the line saving per km is large. Beyond the break-even distance (about 500–800 km overhead, 30–50 km cable) HVDC has lower total cost.

So for long lengths (above break-even distance) HVDC is the better choice; for short lines HVAC remains cheaper.

A grid-connected power system is one in which generating stations and loads of different regions are connected through a common transmission network (the grid) and operated together, e.g. the Integrated Nepal Power System (INPS) under NEA.

Merits

1. Reliability of supply: loss of one plant or line is covered by other sources through alternative paths.
2. Reduced reserve capacity: reserve is shared among all plants.
3. Economic operation: cheapest plants (run-of-river hydro) are loaded first; costly diesel/thermal used only at peak.
4. Diversity benefit: regional peaks occur at different times, so required installed capacity is lower.
5. Better frequency and voltage stability: large total inertia and high fault level make the system stiff.
6. Optimal use of hydro: surplus monsoon energy can be exported (e.g. to India) and dry-season deficits imported.
7. Allows larger, more efficient generating units and integration of distributed and renewable plants.

Demerits

1. Higher fault level, needing breakers of higher rupturing capacity.
2. Cascade tripping: a severe fault may spread and cause a nation-wide blackout.
3. Complex control and protection: load-frequency control, tie-line control, scheduling and SCADA are required.
4. Stability issues on long weak tie lines (inter-area oscillations).
5. High capital cost of transmission lines, substations and communication.
6. Small plants must follow strict grid code rules (frequency, voltage, protection settings).