The Generating Equipment is directly involved in converting hydraulic power to electrical power. It comprises:
- turbines
- governors
- generators and
- exciters
They are supported in their functions by numerous pieces of ancillary equipment, which are normally included in the contract for supply of generating equipment.
Table of Contents for this page
- Turbines
- Governors
- Generators
- Exciters
- Complete Generating Unit
- Ancillary Equipment
Turbines
The turbine is the piece of equipment that converts water energy to mechanical energy.
There are many different types of turbine used for hydropower. The three most common types cover all the usual ranges of available head and flow. These are:
- the Pelton turbine;
- the Francis turbine; and
- the Kaplan turbine.
All are named after their inventors (Lester Allan Pelton, James B. Francis and Viktor Kaplan). The chart below shows the ranges of head and flow where they are used.
As you will see from the chart:
- Pelton turbines are designed for high heads and relatively small flows.
- Kaplan turbines are designed for low heads and high flows.
- Francis turbines are designed for all other flows.
A turbine of any type must still be designed for the specific flow and head at your site. The chart does NOT mean that a turbine of any type can operate anywhere in the demarcated zone.
For example, a Francis turbine designed for low head and flow can’t be used at the high head / high flow region of the area outlined in yellow.
On the next few pages, let’s look at the most common turbine types.
As you will see from the chart:
- Pelton turbines are designed for high heads and relatively small flows.
- Kaplan turbines are designed for low heads and high flows.
- Francis turbines are designed for all other flows.
A turbine of any type must still be designed for the specific flow and head at your site. The chart does NOT mean that a turbine of any type can operate anywhere in the demarcated zone.
For example, a Francis turbine designed for low head and flow can’t be used at the high head / high flow region of the area outlined in yellow.
On the next few pages, let’s look at the most common turbine types.
Impulse Turbines
If you ever laid your bike on its side and washed it with a garden hose, you probably found that when you were spraying water onto the tires, it made the wheel turn. The jet of water applied an impulse force to the wheel rim and created a simple impulse turbine.
Many impulse turbines were developed over the years, but finally, in the 1870s, Lester Pelton developed a sophisticated and efficient design. He attached specially-shaped buckets to the outer rim of the water wheel directed a jet of water from a nozzle towards the centre of these buckets. The buckets were shaped like two adjacent pairs of spoons to direct the flow back towards the nozzle.
The momentum of the incoming water was converted to an impulse of force applied to the bucket. As the wheel turns, the bucket moves out of the path of the jet, but not before another bucket has taken its place. As shown below, the water loses all its velocity as it passes through the bucket, and falls straight down to the tailrace below.
The runner (moving part) of a Pelton turbine is sometimes cast as a single piece, complete with all the spoon-shaped buckets around its circumference.
However, when the runner is large, or when the supply water contains a high concentration of sediment, replaceable, bolt-on buckets are used.
Usually a Pelton turbine has several nozzles directed at the runner, as shown in the figure. Each nozzle is equipped with a needle valve to regulate the flow discharge directed at the runner. In front of each nozzle there is a flow deflector that can move quickly in front of the nozzle and direct the nozzle flow away from the runner and directly to the tailrace.
Why is the turbine is designed so that the buckets move at half the speed of the water jet? Take a look at the sketch below. The water enters the bucket at a speed of 2V, but the bucket is moving away from the vet at a speed of V, so the speed of the water relative to the bucket is V. After the water makes a U-turn in each side of the bucket, it is moving at a speed of -V relative to the bucket, which means it has an absolute speed of zero. This is why the water falls down to the tailwater with very little residual velocity (or energy). This results in a turbine with an efficiency approaching 80%.
The diameter of the runner and the rotational speed of the Pelton turbine is selected to suit the generator design, which allows the generator to be coupled directly to the turbine shaft without the need for a gearbox.
Where are Peltons used?
Impulse turbines are most suitable when the available water source has relatively high hydraulic head at low flow rates. If a large flow is available, more turbines are used.
Impulse turbines are made in all sizes, from a few watts to 400 MW and have been used for heads as low as 30 m to over 1800 m.
Pelton benefits and limitations
One of the advantages of a Pelton turbine is that the turbine power can be instantly reduced to zero by moving the deflectors in front of the water nozzles. This greatly reduces the speed rise that turbines and generators commonly experience when the load is instantly removed due to an electrical fault. Once the deflectors are deployed, the needle valves in the nozzles are closed slowly to limit the transient pressure rise in the water conveyances.
One limitation of Pelton turbines is that they must rotate in air. (If immersed in water, virtually all the turbine power would be destroyed through turbulence.) This means that the turbine setting (i.e. the elevation of the turbine runner) must be located above the highest flood level that the tailrace can experience. This means that most of the time the runner is operating well above tailwater level. Since the hydraulic head on the turbine depends on the elevation difference between the upstream pool level and the Pelton turbine setting, some head (and power is wasted all the time. Fortunately, Peltons are normally used under high and very high heads, so the loss of head is relatively minor.
Francis Turbines
There are more Francis turbines in use today than any other type of turbine. This is because they can be adapted to suit a huge range of flows and heads, whereas Pelton turbines suit high heads with low flows and Kaplans suit low heads with high flows.
Francis turbines are “reactive turbines” and use both the hydraulic head and the velocity head to produce mechanical power. The hydraulic head produces a pressure difference across the runner blades and drives them around, while the kinematic head is lost as the flowing water transfers its momentum to the turbine blades.
The key components of the Francis turbine are discussed below, but first you can explore the main parts of a turbine by clicking the buttons on the animation below.
Spiral Case
Like the Pelton wheel, the water enters the turbine in a volute or spiral case – a water passage that distributes flow to the turbine entrances. While the Pelton has a few nozzles for directing water onto the runnel, the spiral case of a Francis turbine distributes water flow all around the perimeter of the turbine entrance – which is why the spiral case is also called the “distributor”. As water flows around the spiral case and into the turbine, the amount of flow gradually reduces. To avoid a change in velocity
Like the Pelton wheel, the water enters the turbine in a volute or spiral case – a water passage that distributes flow to the turbine entrances. While the Pelton has a few nozzles for directing water onto the runnel, the spiral case of a Francis turbine distributes water flow all around the perimeter of the turbine entrance – which is why the spiral case is also called the “distributor”. As water flows around the spiral case and into the turbine, the amount of flow gradually reduces. To avoid a change in velocity (which would cause head loss and therefore loss of turbine efficiency), the cross sectional area of the spiral case also decreases all the way round, like a snail shell.
Stay Ring and Stay Vanes
The turbine entrance has a series of “stay vanes” (static blades) that direct the flow onto the turbine runner at the most efficient angle. These vanes also support the weight of the turbine and structural components above, so they are held by a heavy “stay ring”. The segments of the spiral case are welded to the top and bottom of the stay ring.
Wicket Gates and Operating Ring
Inside the stay vanes it a set of movable vanes, called “guide vanes” or “wicket gates”. These have a shaft top and bottom, secured by bushings inserted in holes in the stay ring. The upper shaft extends above the stay ring and an arm is attached to it. There are metal plates (links) between the arms and an “operating ring”. When the ring rotates, the links move all the arms together to move the wicket gates. When the tail of each wicket gate touches the nose of the next wicket gate, they stop water from entering the turbine (apart from some leakage). When the operating ring moves the other way, the vanes open to allow more water into the turbine. When the wicket gates are wide open, they are at “100% gate” and the maximum flow is admitted to the turbine and the turbine produces maximum power. However, the flow conditions are not perfect at 100% gate – the point of best efficiency occurs at a somewhat lower gate opening (and flow).
The flow rate through the turbine is regulated by moving the operating ring to open or close the wicket gate. The operating ring is moved by a pair of servomotors (large hydraulic cylinders), one of which pushes while the other pulls. Click the buttons on the animation below to see how this works.
Kaplan Turbines
Kaplan runners look rather like propellers. In fact, propeller turbines exist. They have very high efficiency at one particular flow and one particular head. A set of wicket gates it sometimes used to control flow through the turbine and water flows axially through a propeller-shaped runner. A small change in flow or head leads to a large drop in efficiency, so they are only useful in very special circumstances.
By contrast, the Kaplan has both wicket gates to regulate flow, and feathering blades (blades that can pivot to adjust their angle to the flow) to maintain good efficiency over a fairly wide range of heads and flows.
As shown in the top photo, Kaplan turbines can be mounted vertically or horizontally.
In the vertical configuration, either a spiral case or semi-spiral case may be used to distribute water to the turbine inlet. The picture below shows the geometry of a concrete semi-spiral case, which is used when there is no penstock upstream of the turbine.
Viewed from the side, this arrangement looks like this:
Like a Francis turbine, the Kaplan turbine inlet comprises fixed stay vanes and pivoting guide vanes mounted on a stay ring.
There are may horizontal configurations, but the most common are the pit, the bulb and the S-turbine.
Pit
In the pit configuration, the water flows around a steel tower. to a horizontal Kaplan turbine downstream. The shaft passes into the pit and is connected to the generator. If the turbine speed is too low, a speed increaser (gearbox) is placed between the turbine and the generator. If the pit is too small for a generator, the output shaft of the gearbox is vertical, and the generator is mounted on the floor above the top of the pit, like this:
Bulb
A bulb turbine is similar to a pit turbine in that the generator is mounted upstream of a horizontal Kaplan turbine. The difference is that the turbine (and gearbox if required, is mounted in a watertight steel bulb structure within the water passage instead of a pit, like this:
S-Turbine
This arrangement uses a jog in the alignment of the water passage to place the generator outside of the water passage, rather than using a bulb or pit, like this:
Draft Tubes
When the water leaves a Francis or Kaplan turbine, it passes through a water conveyance called a “draft tube”. the purpose of the draft tube is to recover the velocity head in the water so that it does not go to waste.
There are two components of the flow velocity at the turbine exit:
The draft tube recovers energy from both these flow components.
To recover the energy from the axial flow component, the flow area gradually increases from the inlet to the exit of the draft tube. (The velocity head is proportional to the square of the velocity head, Hv = V²/2g ). It is generally desirable to reduce the exit velocity to 2 or 3 m/s. A lower exit velocity requires a longer, more costly draft tube, but the energy savings continue for the life of the generating plant.
To recover energy from the swirl component of flow, the draft tube gets shallower and wider near the inlet, which slows the rotation of the flow.
This wide, shallow shape also prevents secondary currents as the flow passes around the vertical bend from the vertical inlet to the horizontal exit. This reduces losses in this bend.
Gates or stop logs are installed in the draft tube (normally near the downstream end). If the turbine flow is large or the selected exit velocity is small, the exit width and height might require a gate that is too large and costly. Then one or more piers is introduced in the draft tube, and the draft tube exit is fitted with two gates or two sets of stop logs.
The interactive animation below allows you to explore how the shape of the water cross section varies from the draft tube inlet to outlet. In the example below, there is one pier in the draft tube, causing the flow to split in half.
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Turbine Efficiency
Water turbines are designed for a specific range of head and flow, and generally convert the potential energy of the incoming water flow with a peak efficiency greater than 90%.
The peak efficiency generally occurs at the Rated Flow and Rated Head. The efficiency is lower at flows that are greater or less than the Rated Flow, and at heads that are greater or less than the Rated Head.
The efficiency over the operating range of a turbine is represented by a series of contours on a graph. As you can see in the illustration below, it looks rather like a contour map of a hill, so it is known as a “Hill Chart”. Hill Charts are normally black and white, but I have added colour for emphasis.
If you walked up and over the “hill” on the line marked Q-Q, you would rise and fall on your journey. This shows how efficiency would rise and fall if we varied the head at a constant turbine flow rate.
If you walked up and over the hill on the line marked H-H, you would get a similar rise and fall. This shows how efficiency would vary if we varied the turbine flow while keeping the head constant.
The rate at which the efficiency changes with changing flow and head depends on the type of turbine.
Pelton turbines have a high efficiency over a wide range of flows, and while the efficiency falls off with reduced head, Peltons are generally used for high head sites where the head is fairly constant;
Francis turbines show a more marked reduction in efficiency away from the Rated Flow and Rated Head. If there are multiple turbines in the powerhouse, some may be shut down when the available flow reduces to keep the remaining units operating near their Rated Flow.
Propeller turbines have very high peak efficiency, but a significant reduction in efficiency when either the flow or head moves away from the Rated values. The problem lies in the fact that the propellor blade angle is set precisely for the incoming flow velocity, and the turbine does not work efficiently at other velocities.
Viktor Kaplan (27 November 1876 – 23 August 1934) recognized this and designed a propellor turbine with the ability to vary the blade angle. The “Kaplan” turbine regulates the incoming flow with wicket gates and regulates the blade angle for maximum efficiency at the incoming flow rate, so it is called a “double-regulated” turbine. It has a slightly lower peak efficiency than a propellor turbine, but a flat efficiency curve, which means that the efficiency does not drop off significantly as the head and flow move away from the peak efficiency point.
Governors
The rotational speed of a synchronous electrical generator determines the frequency of the alternating current that it generates. When a generator is coupled to a hydro turbine, the rotational speed of the unit must be regulated (governed) to keep the frequency of the output power the same as the frequency of the electrical system it supplies.
The equipment that does this vital job is called a governor. It varies the flow through the turbine to adjust its speed and power output. It has three basic systems:
- A speed sensing system;
- An electronic control system;
- A high-pressure unit (HPU).
The output of the system is high pressure hydraulic oil, carried in pipes and connected to the turbine control servomotors-that move the operating ring and open or close the turbine wicket gates.
Speed-Sensing
Starting in the middle of the 19th century, early hydro turbines used a flyball governor to control their speed. If the turbine shaft spins faster than the synchronous speed, the balls fly outwards and a lever reduces the turbine inflow. The widget below shows the motion of the flyballs and levers. Click the buttons to make them move.
This kind of governor needs an oil damper to keep it stable, because it tends to overcorrect for speed changes and become unstable.
Mechanical governors were replaced by mechanical-hydraulic governors, which used the fly-ball position to regulate the turbine inflow via a pressurized hydraulic oil system (usually called a high-pressure unit, or HPU).
Finally, digital governors were developed. They are now supplied with almost all new turbines, and most older turbines have been retrofitted with this technology. The digital governor is an industrial computer. It uses an optical or magnetic speed sensor attached to the turbine shaft as its primary input, and uses Proportional-Integral-Derivative (PID) based control to actuate an HPU and adjust the turbine inflow.
Generators
The electric generator is the piece of equipment that converts the mechanical energy of the turbine to electrical energy.
It works on the principle that when a moving magnetic field cuts an electrical circuit it induces a flow of electric current in the circuit.
Most hydro stations use synchronous generators. This means that the frequency of the electrical output is the same as the transmission system it supplies. However, variable speed turbine generators are sometimes used for pumped storage applications.
The primary components of a generator are a fixed stator and a rotating rotor, as illustrated in the animation below. [Click the red square to stop the generator, or the green arrow to start it.]
Rotor
The moving part of a generator is the Rotor. This is located at the centre of the generator and it is bolted to the top of the turbine shaft. The structural steel frame of the rotor has large radial arms (called the “rotor spider”). Electro-magnets (called “poles”) are mounted on the perimeter of the rotor frame. Each pole is surrounded by an electrical “winding” called a “field winding”. In a very small generator, the winding might actually be a thick copper wire wound around the poles. On most hydro generators, the “winding” is made of thick, insulated copper bars connected together to form loops (“windings”) around the pole. The pole itself is made of soft iron or grain-oriented silicon steel.
The end of one pole winding is connected in series to the winding of the next pole, using a copper bar called an “inter-pole tie”. The winding on adjacent poles is reversed so that one pole forms an electro-magnetic North Pole and the adjacent pole forms an electro-magnetic South Pole.
When designing a rotor, the number of poles is determined from this formula:
Number of poles = Frequency of electrical system x 120 / rated rotational speed
Electrical systems have a frequency of 50 Hertz or 60 Hertz. In North America, the standard is 60 Herz.
So if our turbine has a rated speed of 300 rpm, we need 60 x 120 / 300 = 24 poles.
The “salient pole” rotor described above is used for hydro generators, because they rotate fairly slowly – typically at 200 to 400 rpm. (Steam turbines typically rotate at 3600 rpm and use cylindrical rotors.) Salient pole rotors are very heavy (typically 100 to 800 tonne) and are usually the heaviest load that the powerhouse crane must handle. A beneficial consequence of their high mass is that they have very high rotational inertia, which helps to stabilize the frequency of the power system.
When the generator is in service, the rotor spider and poles are subject to high centripetal forces. For example, the centripetal acceleration on the perimeter of a 5 m-diameter rotor rotating at 300 rpm is 2267.4 m/s², i.e. over 200 times the acceleration due to gravity.
When an electrical generator is tripped (suddenly disconnected from the power system), the turbine speed rises rapidly. If the turbine were not regulated, the speed would rise to a physical limit known as “runaway speed”. The runaway speed is a characteristic of the turbine design.
The speed rise places very large stresses on the rotor components, so they are rarely designed for runaway speed. Normally, the speed rise is limited by the action of the governor, which reduces the turbine flow as quickly as possible. The maximum speed of the rotor in the interim (while the governor is doing this) is used for design of the rotor structural components.
The exciter system (described below) supplies direct current to slip rings on the generator shaft, and these are connected to the rotor pole windings. The flow of current turns the poles into electro-magnets.
Stator
The stator is the static part of the generator which encircles the perimeter of the rotor. As the rotor turns, the magnetic fields from the rotor poles cross electrical conductors (“windings”) in the stator. Each stator winding is made of thick copper bars. The stator windings are connected into three separate electrical circuits, each supplying one phase of the three-phase electrical output of the generator.
The copper stator bars are wrapped with insulation and wedged rigidly in the slots of a “stator core” using fillers and ripple springs. Connections at the top and bottom of the stator bars are designed to reduce harmonics in the output voltage. The core is built up like a layer cake of sheets of soft iron or grain-oriented silicon steel. These sheets are punched out in the correct shape and coated with insulating material (to avoid induced currents that would waste energy and heat up the core) before being “stacked” in a steel frame (the “stator frame”). The stacked punchings are then clamped together tightly with vertical bolts.
When the rotor poles move past the stator windings, alternating electrical current flows in these circuits. These currents create a magnetic fields in the stator core, which react strongly with the magnetic field of the rotor poles (as if trying to slow the rotor). The stator frame is designed to carry these large reactive loads from the stator to the concrete foundation of the powerhouse. The stator connections to the concrete must resist these loads while allowing the stator to expand (as it heats up in use) and contract (when it is shut down for inspection and maintenance).
One end of the three stator circuits is terminated in the Neutral Cubicle (see below). The other end of the circuits is the generator terminal. The circuits are brought out of the generator enclosure and connected to the high voltage system. The voltage on these terminals is typically in the range of 11 kV to 13.8 kV.
Generator Output Rating
The rating of a hydro generator is expressed in MVA (mega volt amps). This is the product of the rms (root-mean square) output current per phase times the rms output voltage per phase time the number of phases. (The alternating voltage and alternating current both follow a sinusoidal pattern. The mathematical value of rms for a sine wave is equal to the peak values divided by the square root of 2.
Generator Cooling
Hydro generators and extremely efficient – typically around 98%. The 2% of power loss occurs due to windage (air flow losses), eddy currents induced in the magnetic cores (eddy losses) and electrical losses due to the resistance in the stator winding (called I² R losses because power loss is the product of the square of the current, I in amps and resistance, R in ohms.
These power losses all generate heat in the generator windings, cores and generator enclosure. If the core or windings were to get too hot, the insulation would break down and allow arcing between the windings and the stator core. Class F insulation is often used for generators and this can tolerate a temperature of 155°C (311°F) for the life of the generator.
The flow of air generated by the rotation of the rotor is used to cool the stator. Ventilation spacers are incorporated in the stacked stator core allow the air to flow. To direct the air flow efficiently with a minimum loss due to windage (friction between the rotor and the air), the top and bottom of the generator are shrouded, usually with an insulating material such as fibre glass.
In smaller generators, fresh air from the powerhouse is admitted to the generator and the heated air is vented into the powerhouse or to the outside. This is called Open Ventilation.
Larger generators (more than about 100 MVA) are cooled by TEWAC ventilation – “totally enclosed water to air cooled” ventilation. In this system, the air circulating in the generator enclosure is cooled by air-water heat exchangers. The water for these coolers is taken from the “raw water” connection to the penstock. It is screened before it is piped to the coolers and the hot discharge water from the coolers is discharged to the tailrace.
Exciters
The generator exciter produces the direct current that supplies the rotor field windings and magnetizes the rotor poles. Nearly all modern hydro generators are self-excited. This means that they are operated by a relatively small amount of power from the output of the generator itself.
Until the 1980s, most exciters were mounted on top of the rotor and were rotary DC current generators. Since that time, static exciters have been used almost exclusively on new machines, and they have been retro-fitted on most existing generators.
The static exciter gets its power from the generator output bus. A 3-phase exciter transformer (or a set of three single-phase transformers) is placed in an electrical panel near the generator busses (often directly beneath the buses), and connections from the buses lead via relays and metering devices to the primary transformer windings. The output from the exciter transformer is passed through a three-phase silicon-controlled rectifier (SCR) to produce direct current. The nominal exciter voltage is typically 125 V for small generators and up to 500 V for large generators.
A modern static exciter has many functions, including reactive power control (VAR Control) and joint control (when there is more than one generator in the powerhouse). However, the primary function of the exciter is to provide automatic voltage regulation. The AVR compares the generator output voltage (measured by potential transformers on the main generator buses) to a reference voltage, and raises or lowers the current in the rotor field windings to maintain a constant output voltage from the stator windings.
This is a simplified description of exciters. For simplicity, it does not cover the numerous other components of used for regulation, protection and control of the generator and the exciter itself.
Complete Generating Unit
The complete assembly is neatly illustrated in this YouTube video produced by Voith Hydro Inc.:
Ancillary Equipment
The Generating Equipment ancillaries are things that are necessary for the operation and maintenance of the primary equipment. Some of these systems are discussed below. [To follow]
Unit Control System
The unit control system is an electrical panel located close to each generating unit which is capable of controlling the generating unit, including starting, stopping and synchronizing it. It is typically equipped with a display screen, manual operating controls, automatic mode controls and communications ports through which it can be connected to a portable computer during testing and commissioning.
The unit board has permanent connections to the SCADA system (see Electrical Auxiliaries) through which the unit is normally operated.
Generator Neutral Cubicle
One side of the generator stator windings are terminated in the Generator Neutral Cubicle. This is an electrical panel that is typically located on the outside wall of the generator enclosure. The neutral cubicle components include accurate current transformers on each phase and a grounding transformer.
Draft Tube Suppression System
A generator rotor has considerable angular momentum (flywheel effect). When a generator is in use and connected to the grid, this momentum helps to stabilize the frequency of the electrical system it is supplying. When the system load increases, there is a tendency for the frequency to fall until this is detected on all the connected generating units and they increase power output to compensate. In the meanwhile, the inertia of all the connected rotors helps to reduce the frequency deviation.
Hydro generating units that are equipped with a draft tube suppression system can contribute their angular momentum to the system even when they are not generating. The system stores a large volume of compressed air and injects this below the turbine runner to force the column of water in the draft tube below the turbine runner.
The turbine is then free to rotate in free air. The unit is normally run up to synchronous speed and synchronized with the transmission system before the turbine inlet valve is closed and the draft tube water level is pushed down, leaving the unit connected to the grid and spinning in the air. As with the operating units, the unit inertia resists any deviation of the system frequency.
Rotor Lifting and Braking
Large hydroelectric generators are equipped with a hydraulic system and jacks that are used to raise the rotor, allowing bearing oil to flood the surfaces of the thrust bearing before the jacks are lowered and the rotor is allowed to turn. The jack surfaces are normally fitted with special brake pads, so when a unit is being shut down, the jacks are raised using a pneumatic system to slow and stop the unit after the turbine power has been shut off. While the jacks may be combined, it is more usual to have separate jacks for rotor lifting and for braking.
The system may include brake pad wear detection and a dust collection system (see below).
Generator Dust Collection System
A dust collection system is generally integrated with the generator brake system to remove brake pad particles that come loose when the brakes are applied. This keeps the air in the generator enclosure clean for the safety of operating personnel and to prevent the dust from contaminating the generator windings.
The dust from each brake pad is carried in tubes to an air filtration unit.
Oil Mist Collection System
The generator bearings carry high loads and tend to produce oil mist. Like the brake dust, oil mist is a contaminant that is unhealthy to breathe and can contaminate the generator windings. To prevent this, large hydroelectric generators are equipped with an oil mist system, which removes the oil mist from the bearings before it enters the atmosphere and pipes it to a filtration system where it is removed.
Turbine Pit Hoist
The turbine pit is located immediately above the turbine and immediately below the generator. It provides access to the moving parts of the turbine for inspection and maintenance. Many of these components are heavy, including wicket gates and servomotors. A turbine pit hoist is therefore provided to lift these components and carry them to the pit entrance, where a cart may be placed to wheel them out of the pit if they need to be replaced or transported to the workshop for machining.
It is usual to use an asymmetrical monorail hoist in this application.
Turbine Pit Lighting
Since most routine turbine maintenance takes place within the turbine pit, good quality pit lighting is provided. In addition, the pit is normally provided with connections for power tools, including compressed air connections, electrical convenience outlets and welding outlets.
Turbine Pit Drainage
Water can alter the turbine pit through the packing seals on the shaft and during maintenance and cleaning operations. This water is normally discharged via drains within the stay vanes and carried to the station sump.
Turbine Runner Access
A turbine runner might wear due to erosion (if the water flowing through the turbine contains sand or silt) or cavitation (if operating conditions of head and flow are poor, or the tailwater level is lower than anticipated). Minor runner damage can be repaired by welding and grinding to bring the runner blades back to their original profiles, but this requires access to the bottom of the runner.
This requires the turbine inlet valve to be closed (or for the penstock to be drained, if there is no TIV), the draft tube gates (or stop logs) to be in place at the draft tube outlet, and the unit unwavering system to remove the water in the unit to a suitable level below the runner.
Then a water-tight door in the draft tube wall is opened (after first opening a stop-cock in the door to confirm that there is no water pressure behind the door).
Beams are then rolled across the width of the draft tube, and custom-designed aluminum floor sections are clipped into place on the beams to provide a working platform. Then temporary lighting and ventilation are installed and workers may enter the draft tube.
Reference Pressure Taps
The performance of a turbine (included the guaranteed efficiency) is based on the head difference between two contractually-agreed locations:
- The Upstream Reference Section, which is located near the turbine inlet; and
- The downstream Reference Section, which is located at the downstream end of the turbine draft tube, immediately upstream of the draft tube gate slots.
Pressure taps are installed at six or eight locations around the flow boundary at the two reference sections, and connected to a mercury manometer board and pressure transducer outside the draft tube.
The differential pressure difference between the two reference sections, expressed in metres of water head, is the Net Head acting on the turbine under any particular operating condition.
Winter-Kennedy Taps
When water flows through a pipe bend, the pressure on the outside of the bend is greater than the pressure on the inside of the bend.
This phenomenon is used to obtain a relative value of flow through the turbine, which is useful for index testing of turbine efficiency. The method is described in the IEC 41 Standard of the International Electrotechnical Commission.
Flow Measurement System
For absolute efficiency measurements, relative flows are not sufficient. Ultrasonic systems are the most common type of flow measurement in use at present. In some cases, the measurement transducers are installed temporarily for an initial warranty test. Some stations have a system of permanent flow transducers, which are used for warranty testing and then to monitor the efficiency of the units during their life. This allows runner repairs or replacements to be planned and scheduled.
The principle of ultrasonic flow measurements is this: Sound travelling through a water flow travels faster in the downstream flow direction than in the upstream flow direction. An upstream transducer is used to emit a pulse of sound – a ping. This is detected by a similar downstream transducer, and the time difference between the emission and reception of the ping is measured very accurately. Then the downstream transducer emits a ping, the upstream transducer detects it, and the time difference is measured again. The difference between the downstream time of travel and the upstream time of travel can then be used to compute the average velocity of the water flow along the path of the sound wave.
By having several transducers around the penstock perimeter, at both the upstream and downstream ends of the flow meter, average flow velocities can be computed for multiple sound paths. A sixteen-path flow meter, can give a flow measurement with an accuracy better than 2%.
Permanent ultrasonic installations are connected to the station SCADA system, to provide real-time flow monitoring.
Installation of a Flow Meter
- a straight length of penstock is selected for installation of the meter;
- This should be at least six diameters downstream of a valve, bend, expansion or other flow disturbance;
- A set of transducers is installed around the perimeter of the penstock at the upstream end of the metering section, and a similar set around the downstream end.
- Temporary transducers may be attached to the inside of the penstock. Permanent transducers are installed in a pressure lock system. To remove the transducer, it is moved out of the flow and into the pressure lock. A valve is then closed to isolate the lock from the penstock. The lock is then opened and the transducer is replaced, and the procedure is reversed.
- The transducer locations are then carefully surveyed.
- The penstock is filled and the ping travel times are recorded with no flow in the penstock.
- When flow begins to flow, the average flow velocity on each path is measured at frequent intervals, and the sum of the average velocities is averaged and reported to the SCADA system.