Flow measurement device

A flow measurement device is an instrument used to measure the rate of flow (discharge) of a fluid — liquid, gas or vapour — flowing through a pipe, channel or open conduit. It gives the quantity of fluid passing a section per unit time (m³/s, litre/min, kg/s, etc.). Examples: orifice meter, venturi meter, nozzle, rotameter, pitot tube, turbine flow meter, electromagnetic flow meter, ultrasonic flow meter, and weirs/notches for open channels.

Rotameter — construction and working principle

A rotameter (variable-area flow meter) consists of a vertical, slightly tapered transparent tube (glass or plastic) with its bore smallest at the bottom and largest at the top, and a "float" (plumb-bob shaped, usually of metal or plastic) inside it. The fluid enters at the bottom and leaves at the top.

Working principle: when the fluid flows upward, it exerts an upward drag force on the float. The float rises until the upward drag force plus buoyancy just balance the weight of the float:

$\text{Drag force} = W_f - F_b = \text{constant}$

Since the weight of the float is fixed, the pressure difference across the annular gap between the float and the tube wall remains constant. As the float rises, the annular area between the float and the tapered tube increases. The flow rate is therefore proportional to this annular area:

$Q = C_d \, A_2 \sqrt{\frac{2gV_f(\rho_f - \rho)}{\rho \, A_f}}$

where $A_2$ = annular area at the float position, $V_f$ = volume of float, $\rho_f$ = density of float, $\rho$ = density of fluid. The height of the float in the tube gives a direct reading of the discharge, read against a graduated scale marked on the tube. Thus the rotameter is a variable-area, constant-pressure-drop device (unlike the orifice meter, which is a constant-area, variable-pressure-drop device).

Applications

1. Measurement of small liquid and gas flow rates in laboratories and pilot plants.
2. Metering of purge flows, cooling water, lubricating oil and chemical dosing in process industries.
3. Measurement of flow of corrosive fluids using glass/PVC tubes and Teflon floats.
4. Purge and carrier gas flow measurement in gas chromatography and analytical instruments.
5. Low-flow measurement in medical equipment (oxygen/anaesthesia gas flow meters).

Note: It must be installed vertically, and the scale is calibrated for a particular fluid density and viscosity, so correction is needed if the fluid or its temperature changes.

Comparison of Soldering, Brazing and Arc Welding

Key points for the answer:

• Soldering gives a low-temperature, low-strength joint used mainly for electrical connections and leak-proof joints.
• Brazing fills the gap by capillary action at a temperature below the melting point of the base metal, giving a strong joint for pipes and dissimilar metals.
• Arc welding melts the base metal itself, so it gives the strongest joint and is used for load-carrying structural work.

Material Properties Required for Steel Used in Radial Gates of Dams

A radial gate (Tainter gate) is a curved steel gate that controls water flow in spillways and outlets of hydropower projects. It is subjected to high hydrostatic pressure, dynamic loading, abrasion from flowing water with silt, and alternating wet–dry conditions. Therefore, the steel used must possess the following properties:

1. High Strength (Yield and Tensile Strength) The gate skin plate, girders, and arms must withstand large hydrostatic thrust without excessive deformation. Steel with yield strength of about 250–350 MPa (e.g., IS 2062 Grade E250/E350 or ASTM A36/A572) is generally used. High strength permits thinner sections and lighter gate weight.

2. Good Weldability Radial gates are fabricated by extensive welding of plates, stiffeners, and arms. The steel must have low carbon equivalent (CE ≤ 0.45%) so that sound welds without cracks, porosity, or heat-affected-zone (HAZ) embrittlement can be produced.

3. Adequate Ductility and Toughness Ductility allows the steel to deform plastically without sudden fracture under impact loads (e.g., floating debris, gate opening shock). Charpy V-notch impact toughness at low temperature is essential to prevent brittle fracture in cold climates.

4. Corrosion Resistance Since the gate remains in contact with water continuously, the steel must resist corrosion. This is achieved by using weathering steel or by applying protective coatings (epoxy painting, metallizing with zinc/aluminium) and providing a corrosion allowance of 1–3 mm on plate thickness.

5. Abrasion Resistance Silt-laden water causes abrasion of the skin plate and seal surfaces. Steel with adequate hardness (or hard-facing at seal contact areas) is preferred.

6. Fatigue Resistance Repeated opening and closing of the gate and fluctuating water loads cause cyclic stresses. The steel must have good fatigue strength, ensured by smooth weld profiles and avoidance of stress concentrations.

7. Homogeneity and Weldability of Thick Sections For large gates, plates up to 25–40 mm thick are used; the steel must be internally sound (free from laminations, segregation) and weldable in thick sections.

8. Good Machinability and Formability The skin plate is rolled into a cylindrical (arc) shape, so the steel must have sufficient formability without cracking.

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Phase Transformation

Phase transformation is the change of one phase (crystal structure) of a material into another phase due to a change in temperature, pressure, or composition. In steel, the transformation occurs between the allotropic forms of iron:

• α-iron (BCC) — stable at room temperature, called ferrite.
• γ-iron (FCC) — stable between 910°C and 1394°C, called austenite.
• δ-iron (BCC) — stable above 1394°C up to melting point.

When steel is heated above the upper critical temperature (A₃ ≈ 723–910°C depending on carbon content), ferrite + pearlite transform into austenite. On slow cooling, austenite transforms back to ferrite + pearlite. On rapid cooling (quenching), austenite transforms to martensite (a supersaturated, hard, brittle BCC/BCT phase) instead of ferrite + pearlite. On intermediate cooling, bainite forms. Thus the final microstructure — and hence the mechanical properties — depends on the cooling rate. This is the basis of heat treatment.

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Heat Treatment Process for Steel

Heat treatment is the controlled heating and cooling of steel in the solid state to obtain desired mechanical properties (hardness, strength, ductility, toughness) by altering its microstructure. The main processes are:

1. Annealing

• Steel is heated to about 30–50°C above the upper critical temperature (A₃), held there for sufficient time (soaking) to allow complete austenitisation, then cooled very slowly in the furnace.
• Result: coarse pearlite, soft, ductile, stress-free steel. Used to soften steel for machining and to relieve internal stresses.

2. Normalising

• Steel is heated to about 30–50°C above A₃, soaked, then cooled in still air.
• Result: finer pearlite than annealing, higher strength and hardness, improved machinability. Used to refine grain structure after forging or rolling.

3. Hardening (Quenching)

• Steel is heated above A₃ (for hypoeutectoid) or above A₁ (for hypereutectoid), soaked, then quenched rapidly in water, oil, or brine.
• Result: martensitic structure — very hard and wear-resistant but brittle. Used for gate rollers, pins, seals, and cutting tools.

4. Tempering

• Quenched steel is reheated to a temperature below A₁ (150–650°C), soaked, then cooled.
• Result: relieves internal stresses, reduces brittleness, and adjusts hardness/ toughness. Hardening is always followed by tempering (Quench + Temper = "QT" steel).

5. Case Hardening (Surface Hardening) Used where a hard wear-resistant surface with a tough core is needed:

• Carburising: steel is heated in a carbon-rich medium at 900–950°C so carbon diffuses into the surface, followed by quenching and tempering.
• Nitriding: nitrogen is diffused into the surface at 500–550°C in an ammonia atmosphere; no quenching needed.
• Induction/Flame hardening: the surface is rapidly heated by induction or flame and immediately quenched.

6. Austempering and Martempering

• Austempering: quenching in a molten salt bath held at 250–400°C, giving bainite — tough and ductile with good strength.
• Martempering: interrupted quenching in a salt bath just above Mₛ, then air cooling, to reduce distortion and cracking.

Application to Radial Gates: For gate components such as rollers, trunnion pins, and seal bolts, hardening followed by tempering (QT) is used to obtain high surface hardness with a tough core. For the fabricated skin plate and girders, normalising or stress-relieving annealing is done after welding to relieve residual stresses and improve toughness.

Working principle of the Rankine cycle (6 marks)

The Rankine cycle is the ideal cycle for steam power plants (e.g. thermal plants using boiler, turbine, condenser and feed pump). Water is the working fluid and it changes phase during the cycle. It has four processes:

On the T-s diagram the cycle is a closed loop 1-2-3-4-1; the area enclosed is the net work per kg of steam, and the area under 4-1 is the heat supplied.

$\eta_{th} = \frac{W_{net}}{Q_{in}} = \frac{(h_1-h_2)-(h_4-h_3)}{h_1-h_4}$

Since pump work is very small compared with turbine work, $\eta_{th} \approx \dfrac{h_1-h_2}{h_1-h_4}$.

Methods of increasing thermal efficiency (4 marks)

Efficiency rises if the mean temperature of heat addition $T_{m1}$ is raised or the temperature of heat rejection $T_2$ is lowered, since $\eta \approx 1 - T_2/T_{m1}$.

(a) Increasing boiler pressure. Saturation temperature rises, so $T_{m1}$ increases and efficiency improves. Limit: the exhaust steam becomes wetter (low dryness fraction), causing blade erosion, and higher pressure needs stronger, costlier materials.

(b) Superheating the steam. Raising the turbine inlet temperature at constant pressure increases $T_{m1}$ and also raises the dryness fraction at turbine exhaust. Limit: metallurgical strength of boiler tubes and turbine blades.

(c) Lowering condenser pressure. Lowers the heat rejection temperature $T_2$, giving more work. Limit: the temperature of cooling water available and the wetness of exhaust steam; the pressure cannot go below the saturation pressure of the cooling-water temperature.

(d) Reheating. Steam is expanded in the HP turbine, returned to the boiler to be reheated at constant pressure, then expanded in the LP turbine. This keeps the exhaust dry (about 0.88 or more) and allows a higher boiler pressure; efficiency gain is small but work output rises.

(e) Regenerative feed heating. Some steam is bled from the turbine to heat the feed water in feed heaters before it enters the boiler. Heat is then added at a higher mean temperature, bringing the cycle closer to the Carnot cycle.

(f) Binary or combined cycles. A topping cycle (gas turbine, or mercury/other fluid) rejects heat to generate steam in a bottoming steam cycle. The wide temperature range is used better, giving overall efficiency of about 50-60%.

Project Evaluation Techniques: IRR, Benefit–Cost Analysis and Break-even Analysis

1. How the techniques differ from each other

Internal Rate of Return (IRR)

• IRR is the discount rate at which the Net Present Value (NPV) of a project becomes zero, i.e. the rate at which the present worth of cash inflows equals the present worth of cash outflows.
• Decision rule: accept the project if IRR ≥ Minimum Attractive Rate of Return (MARR); among mutually exclusive projects, choose the one with the highest IRR.
• It is expressed as a percentage rate of return and is found by solving:

$\text{NPV} = \sum_{t=0}^{n}\frac{C_t}{(1+r)^t} = 0 \quad \Rightarrow \quad r = \text{IRR}$

• It uses discounted cash flow and considers the time value of money, but ignores the absolute size of the investment and can give multiple or misleading values when cash flows change sign more than once.

Benefit–Cost (B/C) Analysis

• It compares the present worth of benefits with the present worth of costs, usually expressed as a ratio:

$\text{BCR} = \frac{\text{PW of Benefits}}{\text{PW of Costs}}$

• Decision rule: accept if BCR ≥ 1 (or if net benefits = PW(B) − PW(C) > 0).
• It is mainly used for public/social projects (roads, irrigation, hydropower, water supply) where benefits are social rather than commercial revenue. It requires identification and monetisation of intangible social benefits and costs, and uses a social discount rate rather than a market interest rate.

Break-even Analysis

• It determines the volume of output or sales at which total revenue equals total cost, so that there is neither profit nor loss:

$Q_{BE} = \frac{F}{p - v}$

where F = fixed cost, p = selling price per unit, v = variable cost per unit.

• It is a non-discounting, short-run technique based on cost–volume–profit relationships. It does not consider the time value of money; it shows the margin of safety and the output level needed to avoid loss.

Key differences in summary

2. Roles in engineering economic decision making

IRR is used to judge whether a proposed plant, machine or process earns more than the cost of capital. It is widely used in industry because managers can compare the project return directly with the lending/borrowing rate. However, since it ignores project size, it should be used along with NPV when comparing projects of different scales.

Benefit–Cost Analysis is the standard tool for government and public-sector investment appraisal. It helps decide whether a bridge, irrigation canal or rural electrification scheme is worth the taxpayers' money, by bringing all social benefits and costs to a common present-worth basis. It also helps rank competing public projects under a limited budget.

Break-even Analysis guides operational and capacity decisions: how much must be produced and sold to cover fixed costs, what price to charge, whether to buy a more automated (higher fixed cost, lower variable cost) or a labour-intensive (lower fixed cost, higher variable cost) alternative, and how much cushion (margin of safety) exists if demand falls.

In practice, an engineer-economist does not rely on one technique alone. A typical decision sequence is: use break-even analysis to check the required output and cost structure, use IRR/NPV to confirm the project's profitability against MARR, and use benefit–cost analysis when the project has significant social or public dimensions. Together they give a complete picture of profitability, social worth and operational feasibility, which is the essence of sound engineering economic decision making.

1. CPM (Critical Path Method) — 2 marks

CPM is a deterministic network scheduling technique used in project management to plan, schedule, coordinate and control projects whose activity durations are known with reasonable certainty. It was developed by DuPont in 1957.

In CPM, the project is broken into activities, their logical sequence is shown as a network diagram, and the longest path from start to finish is found. This longest path is called the critical path, and its total duration gives the minimum possible project completion time. Activities on this path have zero float, i.e. any delay in them delays the whole project.

2. Example and why we use Critical Path Analysis — 3 marks

Consider a small construction/installation project:

The possible paths are:

$A \to B \to D \to F = 2+3+2+4 = 11 \text{ days}$

$A \to C \to E \to F = 2+4+3+4 = 13 \text{ days}$

So the critical path is:

$A \to C \to E \to F$

and the project duration is 13 days.

Why we use Critical Path Analysis:

• It identifies the activities that control the project duration. Here, C, E and F are critical; if C is delayed by 1 day, the project becomes 14 days unless corrective action is taken.
• It shows where float exists. Activities B and D have total float of 2 days each. A delay of up to 2 days in B or D will not delay the project.
• It helps in resource allocation. Workers or equipment can be shifted from non-critical activities B/D to critical activities C/E/F without delaying the project.
• It helps in time–cost trade-off/crashing. To reduce the project from 13 to 12 days, we must shorten a critical activity such as C, E or F. Shortening B or D alone will not reduce project duration.
• It provides a basis for monitoring and control. Management can focus attention on critical activities and take timely corrective action.

3. Procedure and steps to find the critical path — 5 marks

The critical path is found by the following steps:

1. List activities and dependencies
   Identify all activities, their immediate predecessors and their durations. Draw the network diagram using either Activity-on-Arrow (AOA) or Activity-on-Node (AON) convention. Use dummy activities if necessary to show correct logic.

2. Forward pass — calculate ES and EF
   Start from the first activity with $ES = 0$.
   For each activity: $ES = \max(EF \text{ of all immediate predecessors})$ $EF = ES + \text{Duration}$ The maximum $EF$ at the final activity gives the project completion time.

3. Backward pass — calculate LF and LS
   Start from the last activity with $LF =$ project completion time.
   For each activity: $LF = \min(LS \text{ of all immediate successors})$ $LS = LF - \text{Duration}$

4. Calculate total float
   For each activity: $TF = LS - ES = LF - EF$ Total float is the spare time available without delaying the project.

5. Identify critical activities and critical path
   Activities with $TF = 0$ are critical activities. The continuous chain of critical activities from start to finish is the critical path. If more than one chain has zero float, there are multiple critical paths.

6. Verify and use
   Check that the sum of durations along the critical path equals the project duration. Mark the critical path on the network. Use it for scheduling, resource leveling, crashing and progress control.

For the above example, the computed values are:

Hence, the critical path is:

$A \to C \to E \to F$

with project duration $= 13$ days.

A daily load curve is a graph of the load (power demand) on a power plant plotted against time over 24 hours. The area under the curve gives the energy generated in a day.

Typical daily load curve for a hydropower plant:

Load (MW)
  |
Pmax |          ****
     |         *    *
     |        *      *
     |       *        *
     |      *          *
     |     *            *
     |    *              *
     |   *                *
Pmin |***                  ****
     |________________________|______ Time (h)
     0   6   12   18   24
        (night) (day) (evening peak)

• 00:00–06:00 — Base load, minimum demand (Pmin), mostly domestic lighting off.
• 06:00–12:00 — Load rises as industry and offices start.
• 12:00–17:00 — Fairly steady daytime load.
• 17:00–22:00 — Peak load (Pmax) due to lighting, cooking, TV, and industrial evening shift.
• 22:00–24:00 — Load falls back toward base.

How the load curve helps in planning plant operation and sizing:

1. Fixing installed capacity — The peak of the curve (Pmax) plus a reserve margin decides the installed capacity of the plant. The plant must be able to meet Pmax.

2. Deciding unit commitment / scheduling — The curve shows when to start or stop generating units. Base load is carried by the most efficient units; peaking units are run only during the evening peak.

3. Load factor calculation — Load factor = Average load ÷ Peak load. A high load factor means better utilisation of installed capacity and lower cost per unit of energy.

4. Sizing of reservoir / pondage — The area under the curve gives daily energy demand. This fixes the storage volume needed to match variable inflow with variable demand (especially for run-of-river plants with pondage).

5. Selection of turbines and generators — The range Pmin to Pmax decides the number and type of units (e.g., one large base unit + one small peaking unit) so that each runs near its best efficiency point.

6. Economic operation — By knowing the load pattern, the operator allocates generation among plants to minimise fuel/water cost while meeting the load at every instant.

7. Planning maintenance — Light-load periods (early morning) are chosen for maintenance so that supply is not interrupted.

Thus the daily load curve is the basic tool for deciding how much capacity to install and how to operate it hour by hour for reliable and economic supply.

Synchronous generator on isolated load vs. on a large power system

1. Connected to an isolated load

• The generator is the only source of both active and reactive power. Load changes directly disturb it.
• Frequency control: Frequency is set by the balance between the prime-mover (turbine) input power and the load. If load increases and the governor does not act, the rotor slows down and frequency falls. Frequency is regulated by the speed governor acting on the turbine inlet valve — this is the only frequency-control loop available. Even so, a steady load change leaves a steady-state frequency error (droop), so frequency is never held exactly at 50 Hz.
• Voltage control: Terminal voltage is set by the field excitation. On load change, the armature reaction and the internal impedance drop change the terminal voltage. The automatic voltage regulator (AVR) adjusts field current to restore voltage. Since the generator alone supplies the load, the AVR must supply the entire reactive power demand, and voltage regulation is poorer.
• Both frequency and voltage are thus directly and strongly coupled to the load; the generator "feels" every load variation.

2. Connected to a large (infinite) power system

• The system behaves as an infinite bus: its frequency and voltage are fixed and unaffected by this one generator.
• Frequency control: The generator runs synchronised at system frequency. Its speed is locked to the bus; it cannot change frequency. The prime-mover input now controls only the active power (real power) output of the machine, not the speed. Load sharing among generators is decided by their governor droop characteristics (load–frequency droop), and overall system frequency is regulated by the load frequency control (LFC) of the system operator. A single generator cannot alter system frequency.
• Voltage control: Terminal voltage is fixed by the bus. The field excitation now controls only the reactive power output of the machine. Over-excitation delivers reactive power to the system; under-excitation absorbs it. The AVR therefore regulates reactive power (power factor), while system voltage is held by the automatic voltage regulators and reactive power compensation of the whole system.
• Frequency and voltage are thus decoupled from this generator's control: governor → active power, excitation → reactive power.

Summary

In short, on an isolated load the generator must control both frequency and voltage itself; on a large system it merely supplies controlled active and reactive power while the system controls frequency and voltage.

Major Electrical and Mechanical Components of Hydroelectric Power Plants, Hydro-Turbine Selection, and Working Principle of Governor

1. Major Electrical and Mechanical Components (3 marks)

A. Mechanical Components

B. Electrical Components

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2. Hydro-Turbine Selection Process (3 marks)

The turbine type is selected mainly on the basis of net head (H) and discharge (Q), along with specific speed, capacity, and site conditions.

Step 1 — Determine site parameters: Measure/estimate net head (H) and design discharge (Q) from hydrological and topographical studies.

Step 2 — Compute power: P = ρ g Q H η (kW), where η is overall efficiency.

Step 3 — Compute specific speed: $N_s = \frac{N\sqrt{P}}{H^{5/4}}$ where N = synchronous speed (rpm), P = power (kW or hp), H = net head (m).

Step 4 — Select turbine type based on head:

Step 5 — Check specific speed against synchronous speed: N = 120 f / p (f = 50 Hz, p = number of pole pairs). The turbine must match the nearest synchronous speed.

Step 6 — Consider other factors: part-load efficiency, cavitation (Thoma's σ, NPSH), sediment load (abrasion → Pelton preferred for high silt), runner material, cost, and manufacturer's recommendations.

Step 7 — Final selection: Choose the turbine that gives best efficiency over the expected operating range at minimum cost.

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3. Working Principle of Governor (4 marks)

Definition: A governor is an automatic control device that maintains the speed (and hence frequency) of the turbine-generator set constant by regulating the water flow through the turbine, irrespective of load variations.

Basic Principle: The governor works on the principle of feedback control. When the electrical load on the generator increases, the speed tends to fall; when load decreases, speed tends to rise. The governor senses this speed deviation and adjusts the wicket gates (Francis/Kaplan) or needle nozzles (Pelton) to change the water flow, thereby restoring the speed to its rated value.

Main Components:

1. Speed sensing element — flyball/pendulum or electronic speed sensor that detects speed deviation.
2. Pilot valve / distributing valve — controls the flow of oil to the servomotor.
3. Servomotor (relay cylinder) — hydraulic piston that provides the force to move the gate/nozzle.
4. Oil pressure system — sump, pump, accumulator (air vessel) to supply pressurized oil.
5. Feedback linkage (follow-up mechanism) — returns the pilot valve to neutral once the desired gate position is reached, preventing over-correction.
6. Speed droop / permanent droop setting — allows load sharing between parallel units.

Working:

• Load increases: Speed decreases → flyballs move inward → pilot valve moves down → oil flows to servomotor → servomotor opens the wicket gates → more water enters turbine → speed increases back to rated value.
• Load decreases: Speed increases → flyballs move outward → pilot valve moves up → oil flows to opposite side of servomotor → gates close → less water enters → speed decreases to rated value.
• Steady state: When speed equals rated speed, the pilot valve is at neutral, no oil flows, and the gate remains at its position.

Functions of Governor:

1. Maintains constant speed/frequency under varying load.
2. Controls the opening and closing of wicket gates/nozzles.
3. Provides over-speed protection (with emergency shut-off).
4. Enables load sharing in parallel operation.
5. Ensures stable and safe operation during load rejection/acceptance.

Conclusion: The governor is thus an essential closed-loop control system that ensures the quality of power supply by keeping frequency constant and protecting the machine from runaway speed.

1. Thermal power plants and their thermal efficiencies (2 marks)

A thermal power plant converts heat energy obtained by burning fuel (coal, oil, gas, nuclear fuel) into mechanical energy in a prime mover, which then drives an alternator to generate electricity. The main types and their typical overall thermal efficiencies are:

Thermal efficiency is defined as

[ \eta_{th}=\frac{W_{net}}{Q_{in}} ]

where (W_{net}) is net work output and (Q_{in}) is heat supplied by fuel. Major losses occur in exhaust gases, condenser cooling water, radiation, friction and incomplete combustion. Simple gas turbine plants have lower efficiency because a large part of turbine work is consumed by the compressor.

2. Working principle of gas turbine cycle (5 marks)

A gas turbine cycle works on the Brayton cycle. In an open-cycle gas turbine plant, atmospheric air is drawn into a rotary compressor and compressed to high pressure. The compressed air enters the combustion chamber, where fuel is injected and burnt at constant pressure. The high-temperature, high-pressure combustion gases then expand through a gas turbine and produce mechanical work. A part of this turbine work drives the compressor, and the remaining net work drives the generator. Finally, exhaust gases are discharged to the atmosphere.

The ideal Brayton cycle consists of four processes:

1. 1–2: Isentropic compression in the compressor.
2. 2–3: Constant pressure heat addition in the combustion chamber.
3. 3–4: Isentropic expansion in the turbine.
4. 4–1: Constant pressure heat rejection to the atmosphere.

Let pressure ratio be

[ r_p=\frac{P_2}{P_1}=\frac{P_3}{P_4} ]

For cold air standard analysis:

[ q_{in}=c_p(T_3-T_2) ]

[ q_{out}=c_p(T_4-T_1) ]

[ \eta_{th}=1-\frac{q_{out}}{q_{in}} =1-\frac{T_4-T_1}{T_3-T_2} ]

Using isentropic relations,

[ \frac{T_2}{T_1}=\frac{T_3}{T_4}=r_p^{\frac{\gamma-1}{\gamma}} ]

Therefore,

[ \eta_{th}=1-\frac{1}{r_p^{\frac{\gamma-1}{\gamma}}} ]

Thus, the ideal thermal efficiency of a gas turbine cycle depends mainly on the pressure ratio and the specific heat ratio (\gamma). In an actual cycle, compressor and turbine irreversibilities reduce the efficiency, so isentropic efficiencies of compressor and turbine must be considered.

3. How to improve performance of gas turbine power plant (3 marks)

Performance of a gas turbine plant can be improved by increasing thermal efficiency and net work output. The main methods are:

1. Increase pressure ratio: Higher (r_p) increases ideal thermal efficiency. However, beyond a certain limit, net work may decrease because compressor work increases rapidly. Intercooling is used to overcome this.
2. Increase turbine inlet temperature: Raising (T_3) increases both net work and efficiency. It is limited by blade material strength. Use air cooling, film cooling, thermal barrier coatings, superalloys and single-crystal blades.
3. Regeneration: Exhaust gas heat is used to preheat compressed air before it enters the combustion chamber. This reduces fuel consumption and improves efficiency, especially at low and moderate pressure ratios.
4. Intercooling: Cooling air between compressor stages reduces compressor work and lowers compressor outlet temperature. It increases net work and is often combined with regeneration.
5. Reheat: Expansion is done in two turbine stages, and gases are reheated between stages. This increases work output and can improve efficiency at high pressure ratios.
6. Combined cycle: Exhaust heat from the gas turbine is used in a heat recovery steam generator to produce steam for a steam turbine. Overall efficiency reaches about 50–60%.
7. Cogeneration/CHP: Waste heat is used for process heating or space heating, improving overall fuel utilization.
8. Inlet air cooling: Cooling inlet air in hot climates increases air density and mass flow, thereby increasing output.
9. Component improvements: High-efficiency compressor and turbine blading, reduced pressure losses, better combustion, proper cleaning and maintenance improve performance.
10. Advanced cycles: Intercooled-recuperative-reheat gas turbine cycle, humid air turbine cycle, etc., can further improve performance.

In short, simple gas turbine efficiency is low, but by increasing pressure ratio and turbine inlet temperature, applying regeneration, intercooling, reheat, and especially combined cycle or cogeneration, the performance of a gas turbine power plant can be significantly improved.

Maintenance Planning and Maintenance Techniques for Power Plants

1. Maintenance Planning (3 marks)

Maintenance planning is the process of deciding what maintenance work is to be done, when, by whom, and with what resources, so that plant availability, reliability and safety are maximised at minimum cost. It forms the bridge between maintenance policy (decided by management) and actual execution in the field.

Objectives of maintenance planning

• Maximise plant availability and reliability (minimise forced outages).
• Extend equipment life and preserve asset value.
• Control maintenance cost within budget.
• Ensure safety of personnel and equipment.
• Maintain adequate spare parts, tools and manpower.
• Provide a proper record/history for future decisions.

Steps in maintenance planning

1. Inventory and codification of all equipment (turbine, generator, governor, transformers, gates, penstock, etc.).
2. Criticality analysis – classify equipment as critical, essential or non-critical (e.g. by FMEA or ABC analysis).
3. Work identification – from OEM manuals, statutory requirements, past failure history, condition-monitoring data.
4. Work load forecasting and scheduling – annual, monthly, weekly and daily schedules; coordination with generation schedule and reservoir operation.
5. Resource planning – manpower, tools, spares, budget, contractor services.
6. Scheduling and coordination – fixing dates, issuing work orders, coordinating with load dispatch centre for shutdown.
7. Execution, supervision and feedback – recording man-hours, delays, and updating the history card.
8. Review and control – comparing planned vs actual, backlog control, and continuous improvement.

Planning is supported by preventive, predictive (condition-based), corrective, and proactive maintenance strategies, and by tools such as CMMS (Computerised Maintenance Management Systems), Gantt charts, PERT/CPM for overhauls, and spare-part inventory control.

2. Maintenance Techniques/Practices (2 marks)

3. Condition Monitoring in Hydropower Plants (3 marks)

Condition monitoring (CM) is the continuous or periodic measurement of equipment parameters to detect the onset of degradation, so that maintenance can be planned before functional failure.

How it is applied in a hydropower plant

• Sensors are installed at critical locations: accelerometers on turbine/generator bearings, proximity probes for shaft displacement, RTDs/thermocouples for temperatures, pressure and flow transmitters, partial-discharge couplers in generator stator, oil particle counters in the lubrication circuit.
• Data acquisition is done continuously (online) or at intervals (offline) and fed to a condition-monitoring system / SCADA.
• Baseline and trend analysis – a "healthy" signature is recorded at commissioning; subsequent readings are compared and trends plotted.
• Alarm and alarm limits – warning and trip levels are set; when a trend crosses the warning level, a work order is raised in the CMMS.
• Diagnosis – techniques such as FFT/vibration spectrum analysis, envelope analysis, oil wear-debris analysis (spectrometric and ferrographic), thermography, and partial-discharge analysis identify the specific fault (misalignment, unbalance, bearing defect, insulation degradation, cavitation, etc.).
• Decision – maintenance is scheduled during the next available low-load period or planned shutdown, avoiding forced outage.

4. Advantages over Other Maintenance Techniques (2 marks)

1. Reduces unexpected/forced outages – faults are detected while still incipient.
2. Lower maintenance cost – components are replaced only when actually needed, not on a fixed schedule.
3. Longer component life – unnecessary dismantling and re-assembly damage is avoided.
4. Better spare-part and manpower planning – repair is planned in advance.
5. Improved safety – catastrophic failures (e.g. generator winding flashover, bearing seizure) are prevented.
6. Higher plant availability and generation revenue.
7. Provides objective data for RCM and for extending overhaul intervals.
8. Early warning of developing defects allows root-cause correction (proactive).

5. Parameters Monitored in Hydropower Plants (2 marks)

• Vibration – overall velocity/acceleration, frequency spectrum of turbine and generator bearings, shaft relative displacement (eccentricity, run-out).
• Temperature – bearing metal/oil temperature, generator stator and rotor winding temperature, transformer oil and winding temperature, thrust-bearing pad temperature.
• Lubricating oil condition – viscosity, acidity, water content, particle count, wear-metal concentration (Fe, Cu, Cr, Pb), ferrography.
• Partial discharge / insulation – PD magnitude and phase-resolved pattern in generator stator and transformer bushings; insulation resistance, tan-delta, polarization index.
• Pressure and flow – penstock pressure, spiral-case pressure, draft-tube pressure (cavitation detection), cooling-water flow, oil flow.
• Air-gap and magnetic flux – air-gap between stator and rotor, magnetic flux density (detects rotor eccentricity, winding short).
• Speed and load – runaway speed, speed fluctuation, guide-vane and runner-blade position.
• Water quality and chemistry – pH, conductivity, silt content (for erosion), dissolved oxygen.
• Partial discharge in transformer – dissolved gas analysis (DGA) of transformer oil (H₂, CH₄, C₂H₂, CO, CO₂).
• Cavitation and erosion – acoustic emission, draft-tube pressure pulsation, noise level.
• Efficiency/performance – head, discharge, output, specific energy consumption trend.

These parameters, when monitored and trended, give an early indication of mechanical, electrical and hydraulic degradation, allowing maintenance to be planned economically and safely.

Selection, Components and Maintenance of an Air Conditioning System

1. Selection of an Air Conditioning System (2 marks)

The air conditioning system is selected on the basis of the following factors:

1. Cooling load — the heat load (in TR or kW) to be removed, calculated from solar gain, occupants, lighting, equipment and ventilation.
2. Type and use of building — residential, office, hospital, clean room, server room, cinema hall, etc.
3. Capacity and zoning — single large space or many rooms requiring individual control.
4. Type of application — comfort cooling or process/industrial cooling (close tolerance of temperature and humidity).
5. Availability of space — for plant room, ducting, air handling unit (AHU) and cooling tower.
6. Initial cost vs running cost — capital cost, power consumption, maintenance cost and life of the plant.
7. Energy efficiency — high COP/EER/ISEER, part-load efficiency.
8. Local climate and design conditions — DBT/WBT, monsoon humidity, dust level.
9. Refrigerant and environmental aspect — non-ozone-depleting, low-GWP refrigerant.
10. Noise level, reliability and local service support.

On the basis of the above, a suitable system is chosen — e.g. window/split unit for a small room, ductable split or VRF for a hotel/office, and central chilled-water plant with AHU for a large building.

2. Components of an Air Conditioning System and their Functions (5 marks)

A vapour-compression air conditioning system consists of the following main components:

(a) Compressor It is the heart of the system. It draws low-pressure, low-temperature refrigerant vapour from the evaporator, compresses it to high pressure and high temperature, and delivers it to the condenser. Types: reciprocating, scroll, screw and centrifugal. It maintains the pressure difference between the high side (condenser) and low side (evaporator) so that the refrigerant circulates in the circuit.

(b) Condenser It rejects the heat absorbed in the evaporator plus the heat of compression to the outside cooling medium (air or water). The high-pressure superheated vapour gives up heat and condenses into liquid. Types: air-cooled (finned tube) and water-cooled (shell and tube, with cooling tower).

(c) Expansion device (Expansion valve / Capillary tube) It throttles the high-pressure liquid refrigerant to low pressure, thereby dropping its temperature (flash cooling). It also regulates the flow of refrigerant to the evaporator according to the load. Types: capillary tube, thermostatic expansion valve (TXV), electronic expansion valve.

(d) Evaporator (Cooling coil) Here the low-pressure liquid refrigerant absorbs heat from the room air and evaporates into vapour. The air passing over the coil is cooled and dehumidified (moisture condenses on the coil). Thus the evaporator is the component that actually produces the cooling effect.

(e) Refrigerant The working fluid (e.g. R-22, R-32, R-134a, R-410A) that carries heat from the room to the outside by alternately evaporating and condensing.

(f) Air handling unit (AHU) / Fan and filters The blower/fan circulates conditioned air through ducts; filters (coarse, fine, HEPA) remove dust and dirt; the cooling coil and heating coil condition the air; dampers control the air quantity. In central plants, the AHU is the heart of air distribution.

(g) Other accessories

• Cooling tower — cools the condenser water by evaporation for water-cooled plants.
• Expansion tank / receiver — stores refrigerant and accommodates volume change.
• Thermostat / humidistat — senses room temperature and humidity and controls the compressor and dampers.
• Ducts and diffusers — distribute and supply conditioned air uniformly.
• Piping, insulation and valves — carry refrigerant and prevent heat loss/gain.

3. Maintenance of an Air Conditioning System (3 marks)

Maintenance is carried out as preventive (routine), breakdown and predictive maintenance.

(a) Routine/preventive maintenance

• Clean or replace air filters periodically (every 2–4 weeks in dusty conditions).
• Clean the evaporator and condenser coils; remove dust, lint and scale.
• Check and top up refrigerant charge; detect and repair leaks.
• Clean and lubricate fan bearings, check belt tension and alignment.
• Clean the drain pan and drain line to avoid water overflow and fungal growth.
• Check compressor oil level, oil colour and oil pressure.
• Check electrical connections, contactors, overload relays, thermostat and control settings.
• Clean cooling tower, check water level, bleed rate and water treatment chemicals.

(b) Breakdown maintenance

• Attend to complaints such as no cooling, noise, vibration, water leakage, icing of coil, tripping of compressor.
• Replace faulty parts — compressor, fan motor, capacitor, expansion valve, filter drier.

(c) Annual/shutdown maintenance

• Overhaul compressor, overhaul valves, pressure-test the circuit, evacuate and recharge.
• Performance test: measure suction and discharge pressure, superheat, subcooling, ΔT across coil and COP.
• Record all readings in a maintenance log for trend analysis (predictive maintenance).

Proper maintenance reduces power consumption, extends equipment life, maintains design temperature and humidity, and ensures healthy indoor air quality.