FEED WATER PUMP HYDRAULIC COUPLING _VIDEO

FEED WATER PUMP HYDRAULIC COUPLING

Eighty Percentage 80% of thermal power plants has  boiler feed pump , that takes the water from the feedwater system ( from the DA) and provide this water to the boiler system , to generate steam which is responsible for rolling the Turbine,Therefore Generate Electricity.

Normally Feed water pumped to the boiler is pumped to the Boiler's Drum where at the top point of the boiler, so we have to provide big pump that can handle big pressure with great flow to the boiler.

That is happened by this huge pump ( Boiler Feed Pump ) , BFP is usually rotate with 5000 rpm ,150 barg and can provide about 300 T/H.

This big pump needs a prime mover with high  electrical rating - Power Plants usually use Electrical Induction motor - to rotate this pump, the rating of this prime mover is usually about ( 5 MWatts , 6.6 KVolts , 1600 rpm ). It is very huge rating if you imagin , 5 MWatts can provide Electricity to a small town.

so , as you see in the picture ( left hand is the prime mover_motor) , (Right hand is the pump) and what is it at the middle of the picture??

Hydraulic Coupling

Hydraulic Coupling is used to transmit Power in a wear-free manner from a prime mover (driving machine) to a power consumer(driven machine-pump).  the power is transmitted in the following way:-

* by means of a connecting coupling between the driving machine and geared variable speed coupling.

* by means of a step-up gear unit between the input shaft and primary shaft.

* hydro-dynamically by means of the working oil between the primary wheel and the secondary wheel.

* by means of connecting coupling between the driving machine and geared variable speed coupling.

the control at the hydraulic coupling is done by the scoop tube control, it provide infinitely variable adjustment of the driven machine's speed. the power from the driving machine is transmitted to the primary wheel to the working oil, the working oil is accelerated in the primary wheel, and the mechanical energy is converted into the energy of fluid flow. the secondary wheel picks up the flow energy and converts it into mechanical energy. this energy is transmitted to the driven machine.

Speed Control

the speed of the driven machine is infinitely variable. this is accomplished by varying the amount of oil in the coupling during operation with the aid of the adjustable scoope tube.

* Scoop tube advanced as far as possible into the scoop champer of the coupling (0% position):minimum oil ring , minimum speed.

* Scoop tube retracted as far as possible out of the scoop champer of the coupling (100% position): maximum oil ring, maximum output speed.

I attached a small Flash file for Voith Company (shows the movements of Hydro coupling ), AND TWO FILES FROM VOITH

http://www.mediafire.com/?7titf097za3zu0y

http://www.mediafire.com/?j579r5d15ej5q6d

http://www.mediafire.com/?7udd1a9pz1phoow

Can Your Boiler Feed Pump Handle a Deaerator Pressure Transient?

 

“This is part of an article talking about the importance of DA and BFP positions at power plant “

In a typical steam power plant, the boiler feedwater (BFW) pump takes suction from the deaerator (DA) and discharges high-pressure water to the boiler through the feedwater heaters. During normal operation, the DA is supplied with steam turbine extraction steam to mix with and heat the feedwater. Other purposes for the DA are to provide the required net positive suction head (NPSH) for the BFW pump and to serve as a storage tank to ensure a continuous supply of feedwater during rapid changes in BFW demand.

The available net positive suction head provided to a boiler feedwater pump can drop enough during a pressure excursion to cause cavitation and damage to the pump’s internal parts. A careful analysis of various operating profiles can ensure that the pump operates safely during the pressure fluctuations that occur after a steam turbine trip or large load change.

How does the plant designer or operator determine the adequacy of the BFW pump selection or the DA and feedwater system design? It’s not uncommon to find that the BFW pump was originally specified based on steady-state conditions and did not consider the DA pressure transients that occur during a steam turbine trip (with the boiler remaining in service) or a sudden steam turbine load reduction. If the NPSH available to the BFW pump during the pressure transient drops below that required by the pump for only a short period of time, cavitation and damage to the pump internals often result.

An NPSH deficit in an existing system or a new system under development can be avoided by using some very simple analytic tools.

Find the NPSH margin

The deaerator is installed at some elevation above the BFW pump to provide the NPSH required by the pump. By definition, the NPSHr is the total suction head over and above the vapor pressure of the liquid pumped.

The DA elevation minus the dynamic losses in the BFW suction piping between the DA and the BFW pump equals the NPSH available (NPSHa) to the pump. The difference between the value of the NPSHa and that required (NPSHr) by the pump gives the NPSH margin.

The NPSH margin or the NPSH margin ratio (NPSHa/NPSHr) is an important factor in ensuring adequate service life of the pump and minimizing noise, vibration, cavitation, and seal damage. The NPSH margin requirement increases as the suction energy level (for example, high suction specific speed, high peripheral velocity of impeller, and the like) of the pump increases. In the case of the BFW pump, this ratio could be in the range of 1.8 to 2.5. These margins are typically based on steady-state operation.

In addition, the NPSH margin improves the ability of the BFW pump to handle a DA pressure transient. Once a design is determined to have an adequate NPSH margin, the next step is to determine if the NPSH margin is adequate during a pressure transient.

Expect Deaerator Pressure Decay

Immediately after a steam turbine generator trip, turbine extraction steam is no longer available to the deaerator, resulting in decay of the DA pressure. Also during a sudden steam turbine generator load reduction, the extraction steam pressure decreases until the extraction stage supplying the DA can no longer maintain DA pressure. This also results in DA pressure decay as the lower-temperature condensate continues to enter the DA, cooling the stored feedwater

The decrease in DA pressure causes some of the water in the DA storage tank to flash to steam until saturation pressure is reached at the new DA pressure. The water in the BFW pump suction line has a static head exerted on it by the level in the DA storage tank, preventing it from flashing immediately. Therefore, the water in the suction line can be considered as a slug of hot fluid that must be moved through the pump in some finite amount of time. In other words, the pump will not perceive a decrease in vapor pressure (or a decrease in water temperature) until the entire slug of hot water has passed through the pump.

During the passage of the hot-water slug, the combination of high vapor pressure at the pump suction along with a decrease in pump suction pressure (due to DA pressure decay), results in a "critical point" at which the suction pressure may drop below the minimum required pressure (that is, the vapor pressure of the hot-water slug plus the pressure equivalent of the NPSHr). This low suction pressure could result in cavitation damage to the pump internals due to insufficient net positive suction head

Short Residence Time

The time required for passage of the hot-water slug through the pump suction line is the "residence time." Residence time can be expressed as the suction line volume divided by the volumetric flow rate (or, alternatively, as the mass of liquid in the suction line divided by the mass flow rate)

Note that because the vapor pressure at pump suction is modeled to decay only after the residence time has elapsed, the critical point occurs at the end of the residence time interval. The challenge is to determine the DA pressure at this critical point and thereby the system NPSH margin.

Options for Adding NPSH to the System

The main BFW pumps are generally large, high-energy pumps needing large amounts of NPSHr. One solution would be to raise the DA to a higher elevation to increase the NPSHa. This solution is normally not practical or cost-effective. Another approach is to install a low-speed, low-NPSH booster pump upstream of the BFW pump. The booster pump discharge pressure then provides the added NPSH required by the BFW pump. In addition, the same NPSH analysis must be made on the booster pump. The only difference is that in the case of the booster pump arrangement, the critical point and the critical point margin need to be evaluated at the booster pump suction as well as the BFW pump suction.

Additional Transient Condition

An additional transient condition that the system designer must consider occurs during a "hot start." In this situation, steam flash (water-steam mixture) can occur at the pump suction and cause cavitation damage to the pump internals. However, the mechanism causing steam flash is slightly different than what was discussed earlier.

On a plant trip, the DA pressure drops and the water temperature inside the DA drops. However, the pump and suction piping near the pump remain at a higher temperature due to the mass of the metal. As a result, when the pump is operated on a hot restart of the plant, steam flash and cavitation are likely to occur at the pump suction

“This article for, Magdy Mahmoud is manager of engineering for PGESCo., Egypt.”

Open Feed Water Heater (Deaerator)

Open Feed Water Heater (Deaerator)

An open feadwater heater , also called direct-contact and deaerating (DA) heater , is one that heats the feedwater by directly mixing it with bled steam from the turbine. Usually only one DA is used at Power Plant.

Because the pressure in such a heater can’t exceed the turbine pressure at the point of extraction, a pump (Main Boiler Feed Water Pump) must follow the heater. The confluence of steam and water flows makes possible the efficient removal of noncondensables as well as the heating of the feedwater.

The DA heater is usually positioned in the feedwater line at a pressure to prevent air inleakage and at a temperature at which Oxygen retention is least likely. Most DA heaters are designed for Oxygen concentration in the outlet feedwater below 0.005Cm3/L

The DA outlet feedwater is at or near saturation. Pumping saturated water results in cavitation because of the pressure drop below saturated pressure, thus causing flashing on the back side of pump vanes. The DA heater is therefore usually positioned in the powerplant steam-generator house high above its pump by perhaps 60 ft. This provides sufficient pump inlet pressure to render the saturated water compressed (or subcooled) and prevents cavitations.

There are three types of  DA heaters for industrial and utility use.

1) Spray-Type deaerators .

In this type the feedwater enters the heater through nozzles that spray it into the extraction-steam-filled heater space. The water is heated and scrubbed to release the noncondensables gases. A second agitation of the now-heated feedwater by another steam flow is provided by an internal baffling system.

2) Tray-Type deaerators.

Here the feedwater is directed onto a series of cascading horizontal trays. It falls in sheets or tubes from tray to tray and comes into contact with rising extraction steam admitted from the bottom of the tray system. As scrubbing occurs and noncondensables gases and some steam rise, they come into contact with colder water, resulting in a reduced volume of high concentration of noncondensables to vent into the atmosphere.

3) Combination spray-tray deaerator

In this type, the feedwater is first sprayed into a steam-filled space, then made to cascade down trays. This combination type with horizontal stainless steel trays is currently preferred by utilities. 

You noticed that just below the heater, is a relatively large feedwater tank (Storage Tank) which allows sufficient water for rapid load variations.

Steam turbine disassembly

HYDROGEN, SAFETY INFORMATION

Understanding Hydrogen

Hydrogen is no more or less dangerous than other flammable materials, including gasoline and natural gas, according to a fact sheet about hydrogen safety jointly published by the Hydrogen Association and the U.S. Department of Energy’s Office of Energy Efficiency and Renewable Energy. In fact, some of hydrogen’s differences actually provide safety benefits compared with gasoline or other fuels. However, all flammable materials must be handled responsibly. Like gasoline and natural gas, hydrogen is flammable and can behave dangerously under specific conditions. Nonetheless, hydrogen can be handled safely when simple guidelines are observed and the user has an understanding of its behavior.

Comparison with Other Flammable Materials

-Hydrogen is lighter than air and diffuses rapidly — 3.8 times faster than natural gas — which means that when released, it dilutes quickly into a nonflammable concentration.

-Hydrogen rises two times faster than helium and six times faster than natural gas at a speed of almost 45 mph (65.6 feet/second). Therefore, unless a roof, a poorly ventilated room, or some other structure contains the rising gas, the laws of physics prevent hydrogen from lingering near a leak (or near people using hydrogen-filled equipment). Simply stated, to become a fire hazard, hydrogen must first be confined; however, because hydrogen is the lightest element in the universe, it is very difficult to confine. Industry takes these properties into account when designing structures in which hydrogen will be used. The designs help hydrogen escape up and away from the user in case of an unexpected release.

-Hydrogen is odorless, colorless, and tasteless, so human senses won’t detect a leak. However, given hydrogen’s tendency to rise quickly, a hydrogen leak indoors would briefly collect on the ceiling and eventually move toward the corners. For that and other reasons, industry often uses hydrogen sensors to help detect hydrogen leaks and has maintained a high safety record using them for decades.

 

Combustion

-Hydrogen combustion primarily produces heat and water. Due to the absence of carbon and the presence of heat-absorbing water vapor created when hydrogen burns, a hydrogen fire has significantly less radiant heat compared with a hydrocarbon fire. Because a hydrogen fire emits low levels of heat near the flame (the flame itself is just as hot), the risk of secondary fires is lower.

-Like any flammable substance, hydrogen can combust. But hydrogen’s buoyancy, diffusivity, and small molecular size make it difficult to contain and create a combustible situation. In order for a hydrogen fire to occur, an adequate concentration of hydrogen, the presence of an ignition source and the right amount of oxidizer (like oxygen) must be present at the same time.

-Hydrogen has a wide flammability range (4% to 74% in air), and the energy required to ignite hydrogen (0.02 mJ) can be very low. However, at low concentrations (below 10%) the energy required to ignite hydrogen is high — similar to the energy required to ignite natural gas and gasoline in their respective flammability ranges — making hydrogen realistically more difficult to ignite near its lower flammability limit.

Explosion

-An explosion cannot occur in a tank or any contained location that contains only hydrogen. An oxidizer such as oxygen must be present in a concentration of at least 10% pure oxygen or 41% air. Hydrogen can be explosive at concentrations of 18.3% to 59%. Although this range is wide, it is important to remember that gasoline can present a greater danger than hydrogen because the potential for explosion occurs with gasoline at much lower concentrations: 1.1% to 3.3%. Furthermore, there is very little likelihood that hydrogen will explode in open air due to its tendency to rise quickly. This is the opposite of what we find for heavier gases such as propane or gasoline fumes, which hover near the ground, creating a greater danger for explosion.

Asphyxiation

With the exception of oxygen, any gas can cause asphyxiation. In most scenarios, hydrogen’s buoyancy and diffusivity make hydrogen unlikely to be confined where asphyxiation might occur.

Toxicity/Poison

Hydrogen is nontoxic and nonpoisonous. It will not contaminate groundwater (it’s a gas under normal atmospheric conditions), nor will a release of hydrogen contribute to atmospheric pollution. Hydrogen does not create "fumes."

Hydrogen Explosion ACCIDENT AT U.S. , LESSONS !!!!!

Lessons Learned from a Hydrogen Explosion

“THIS ARTICLE GIVE US LESSONS FROM AN ACCIDENT HAPPENED AT U.S. WITH HYDROGEN EXPLOSION,”

-On January 8, 2007, a hydrogen explosion at the Muskingum River Power Plant’s 585-MW coal-fired supercritical Unit 5 caused one fatality, injuries to 10 other people, and significant damage to several buildings. The explosion occurred during a routine delivery of hydrogen when a hydrogen relief device failed, which allowed the contents of the hydrogen tank to escape and be ignited by an unknown source. This article covers the findings of the incident investigation and the actions the plant has taken to prevent a reoccurrence.

-The explosion at Muskingum River Power Plant underscores the importance of implementing safe equipment design and construction as well as proper procedures for handling hydrogen in order to prevent the loss of life and property at power plants.

-The plant, owned by Ohio Power Co., a subsidiary of American Electric Power Co. Inc. (AEP), is located on the west bank of the Muskingum River near Beverly, Ohio. The plant’s Unit 5 has been in service since 1968. Prior to this incident, the plant had a long history of strong safety compliance.

Background to the Explosion

-Hydrogen is used at the Muskingum River plant to cool the unit generators, McCullough explained. He described the standard operating procedures for the delivery of hydrogen to Unit 5.

-"After checking in with the plant security, the vendor’s driver had sole responsibility for the task of unloading the hydrogen," he said. "The vendor delivered hydrogen approximately once or twice a week and had a blanket contract for hydrogen at the plant for many years." McCullough characterized the vendor as "a self-described ‘expert at designing, building and safely operating gaseous hydrogen plants,’ [that] provided its own procedures for unloading hydrogen."

-Despite the routine use of hydrogen at the plant, plant personnel still had to use caution handling the substance because of its inherently hazardous properties (see sidebar). Hydrogen is the lightest element and is highly flammable.

The Explosion

-McCullough explained what happened when the explosion occurred on January 8, 2007.

-"A hydrogen relief device failed, permitting the contents of the hydrogen tank in question to be relieved and be ignited by an unknown source," he said. "The explosion fatally injured the vendor’s driver and also injured 10 others who had been working nearby. The explosion caused significant damage to the unit’s service building, turbine room, and steam generator building"

-McCullough noted that "Ohio Power Co. accident responders and first aid workers responded immediately to the scene to fight the fire and attend to the injured." Local fire department and emergency medical technicians also quickly responded to the incident and assisted with emergency response and evacuation actions

Investigation of the Incident

-In the aftermath of the incident at the Muskingum River Power Plant, AEP personnel conducted their own examination into the cause of the explosion. Due to the fatality and the injuries sustained by workers at the facility, the U.S. Occupational Safety and Health Administration (OSHA) also conducted an investigation that included all parties involved in the incident.

-"The investigation into this event showed that the relief device was a rupture disc that normally would have been built to relieve pressure to prevent catastrophic failure of the hydrogen tanks," McCullough said. "Normally, the device has a fusible bismuth plug that holds the coin-shaped disc in place until temperatures exceed 180 degrees. The device had been replaced by the hydrogen vendor several months prior, when the vendor was on-site to make repairs related to an apparent leak. The replacement relief device assembly did not have a fusible plug to support the disc."

-When the rupture disc failed, the disc, or a piece of fusible plug left in the vent pipe during the replacement several months prior to the explosion, penetrated a bend in the piping, permitting the hydrogen to vent lower down in the area of the tanks as well as up the normal vent path, McCullough explained.

-OSHA brought enforcement actions against the involved entities as a result of the findings from its investigation of the incident. Those actions initially consisted of 18 citations, nine each against the hydrogen vendor and Ohio Power Co. After an informal conference, the number of citations against each company was reduced to eight. Most of the citations were directed at the design and construction of the hydrogen system.

Reducing the Risk

-After the incident, AEP took corrective actions to guard against future problems related to the handling of hydrogen at the plant.

-"Muskingum River Power Plant employees and employees of plants owned by Ohio Power Co. and its sister corporations (AEP employees) took immediate action to prevent recurrence," McCullough said. "The remaining relief devices were verified as being the correct design and constructed with fusible plugs."

-The hydrogen vendor was restricted to delivering only 2,100-psi hydrogen to the site (versus the typical 2,400 psi), and the vendors’ employees are now under observation by AEP employees using a defined procedure, the Job Hazard Analysis and Job Safety Assessment Checklist, McCullough explained.

-AEP has made other changes in plant operations to further ensure that no more hazardous incidents occur at the facility. "In addition to the procedure changes, the hydrogen system was redesigned and rebuilt to eliminate the use of rupture disc – style relief devices," he said. "Now a relief valve system is used that will reset once pressures have been reduced. The cylinders have been moved away from spaces occupied by people, and the structure is protected from vehicle encroachment and ignition sources."

Key Safety Lessons

-In September 2005, a working group with CIGRE (International Council on Large Electric Systems) estimated that there may be more than 40,000 hydrogen-cooled generators in service around the world. Despite the large number of systems that use pressurized hydrogen to cool generators, for the most part, few incidents or problems occur. However, given the inherently hazardous properties of hydrogen, plant staff working with this flammable material need to regularly review both the equipment and handling procedures to verify that there are no problems.

-This case history is intended to be helpful to personnel who deal with hydrogen used to cool the generators at their power plants. Proper management, including safe equipment design and construction and correct procedures for handling hazardous materials, can ensure safe results in dealing with this useful substance.

‘This article for, Angela Neville, JD, Senior Editor “

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Why Hydrogen Gas is the best cooling medium for rotating machines?

Why Hydrogen Gas is the best cooling medium for rotating machines?

Utilization of Hydrogen gas as the cooling medium either for inner-cooled or for conventional type hydrogen cooled units has the following advantages:

1) Hydrogen gas is small in density; therefore decrease windage and ventilation loss.

2) Hydrogen gas has large thermal conductivity and surface heat transfer coefficient, Therefore, the output per unit volume of active material will increase and the limit of maximum practical rating can be made larger than with an air-cooled unit.

3) Freedom from oxygen and moisture results in little corona effect, thereby prolonging the insulation life of the stator coil.

4) Small gas density and closed ventilating system will reduce noise.

5) Hydrogen-cooled machine is convenient for converting into an outdoor type.

-Common gases which are much lighter than air are (hydrogen and helium). Although helium is inert non-flammable, and an ideal medium for ventilating purposes, it cannot be obtained in quantities, which makes its price high and makes it unsuitable as cooling medium,

-On the contrary, hydrogen can be obtained rather inexpensively, and it has advantages over helium in having a small density and better thermal characteristics.

SFETY  NOTE.

-The intensity of explosion of an air-hydrogen mixture varies with the proportion of the two gases present, and also has to do with the gas pressure.

-A curve on which the values of intensity are plotted against the properties of gases will be approximately a sine wave having zero values at (4 % and 75 % hydrogen), and reaching a maximum intensity in between.

          -So we have to take care:-

*Hydrogen and air should never be mixed.

*Carbon dioxide should be used as an intermediate gas when changing air to hydrogen, or from hydrogen to air.

*When charging gas, provide vent to the atmosphere from generator.

New Control Strategies Improve Boiler Dynamic Response (COAL FIRED POWER PLANT)

New Control Strategies Improve Boiler Dynamic Response 

"This article provide a new control strategy to improve dynamic response for steam generator at Coal-Fired power plant, it provide a case study and explain the results for dynamic response"

-The more capable a power-generating unit is of reacting quickly to changes in load demand, the more profitably the unit can be operated. An improvement in load dynamics means that additional control response and capacity can be made available to the power grid. These characteristics are especially in demand in regions where a fast-responding unit can supply energy as ancillary services at a premium price.

-However, the load dynamics of a coal-fired power plant unit are naturally restricted by the sluggish response of the steam generator, with its huge iron mass and the large boiler drum and pipe volumes where steam is stored. Several minutes will pass between a step increase in fuel flow to the coal mills and the steam generator’s response. Fixed times are required to pulverize the coal, transport it to the furnace, and then burn the coal, and those times must be considered in the design of a plant’s boiler controls. An increased firing rate will gradually produce an increased flow of heat to the steam generator and hence the water and steam. Only then can the mass flow of generated steam increase at a constant steam temperature.

Overcoming Inertia the Old-Fashioned Way

-The capacitance in a boiler can be reduced by means of selectively using the areas where energy is stored in a power plant. The most common method of using stored energy is turbine valve throttling. Steam throttling is required when a defined unit load or steam mass flow is reached and the steam pressure upstream of the turbine is increased. If a fast increase in turbine output is required, the appropriate quantity of steam can be discharged by opening the turbine valve, thus immediately increasing generator power.

-The disadvantage is that turbine valve throttling results in a continuous reduction of plant efficiency. Steam pressure also decreases quickly in the event of a rapid load increase as the stored steam is quickly removed from the boiler system. The fuel mass flow rate must therefore be increased disproportionately—first to counteract the rapid decrease in pressure and second to raise the pressure back to its setpoint or original value. The change in pressure and the resultant overfiring also put additional thermal stress on the boiler system.

-In contrast, a nimble and quick-responding control system means that turbine valve throttling can be reduced, which results in a corresponding increase in efficiency and lower-stress operation of the power plant unit. Reducing boiler inertia also results in an increase in the stability of the controlled plant, quicker reaction to changes in load demands, and improved control loop response to faults. The economic benefits extend to a reduction in the cyclic control movements of the overall plant and of boiler stress in general.

-The question for boiler controls designers is, how do you account for the boiler and other system inertia in your boiler control strategy? We propose a new approach that has been shown in testing to reduce actual boiler inertia by over 30%.

Case Study: Improvement without Throttling

-The following case study describes a control strategy that was successfully implemented in a German hard coal-fired unit that used part of the SPPA-P3000 family of solutions from Siemens Energy. The plant in which these new control strategies were implemented is rated at 750 MW gross and has an overall thermal efficiency of approximately 40%. The once-through boiler produces a rated 2,100 tons/hr (4.6 million lb/hr) of steam available at a pressure of 200 bar (2,900 psi) and a temperature of 535C (995F). The necessary firing rate is provided by six coal mills, each of which is assigned eight burners. All the burners of a mill are located on one level of the boiler. The six mills were equipped with a hydraulic grinding pressure adjuster in order to permit implementation of the extended control strategies.

-The new control strategy was based on the SPPA-P3000 Fast Ramp solution to reduce boiler inertia in order to improve the unit’s load dynamics. In the initial phase of the project, the unit was equipped with a modern unit coordinated control structure. The second phase involved the installation of two innovative control modules: a center-of-fire control and an automatic control for mill grinding power designed to reduce the boiler time constant and consequently improve the unit load dynamics. Apart from the retrofit of grinding pressure adjusters for the individual mills, no process engineering changes were necessary.

** Adjusting the Fireball Location

-A number of boilers are equipped with tilting burners so as to make it possible to change the physical position of the fireball in the vertical plane of the combustion chamber. These tilting burners can be used to inject fuel upward or downward into the combustion chamber at a definable angle to the horizontal plane.

-This adjustment is typically used to influence the amount of energy absorbed in the reheater. The higher the position of the fireball in the boiler, the more radiant heat is transferred to the reheater, and vice versa. If the center of the fireball is controlled such that the reheater injection mass flow is just equal to zero in steady-state operation and the reheater outlet temperature is at its setpoint, an overall increase in plant efficiency can be achieved.

-Variation in the height of the fireball can also influence steam generation in the same way as lowering of the fireball causes more heat to be transferred to the evaporator. In the case of a once-through steam generator, the feedwater mass flow must also be increased so as to maintain the required steam enthalpy at the evaporator outlet at a constant level. If so, the increased feedwater mass flow immediately results in an increase in main steam mass flow. As a result, this performance measure can be used for a rapid increase in the steam generating capacity of the boiler. Temporarily lowering the fireball at the start of or during a load increase will result in an overall reduction of the boiler inertia or time constants.

-With drum-type boilers, lowering of the fireball results in increased steam production and lowering of the drum level. Similarly, the boiler delay of drum-type boilers can therefore also be positively influenced using the center-of-fire control method.

-Not all plants are equipped with tilting burners. However, if several mills supply burners on different levels, the position of the fireball can be influenced by trimming the outputs of the various mills. Similarly, level trimming can also be employed to influence the boiler time constant.

-Operation of the coal mills is staggered by the center-of-fire control module during load ramps such that the mills on the lower levels are operated first, followed by those on the higher levels during an increase in load. This initially causes the fireball to be pulled downward so as to accelerate the increase in steam development. When the load increase stops, the fireball returns to its normal position. Figure 1 illustrates test data that show the staggered increase of mill outputs in response to a unit load increase.

**Mill Energy Storage

-The hydraulic adjustment of grinding power in the coal mills is another way to influence the dynamics of the boiler system. Increased grinding pressure, for example, immediately results in an increased grinding rate and consequently an increase in the coal mass flow following an increase in primary air. Based on the assumption that the feeder rate, or coal fed into the mill, remains constant, the level of coal in the mill will decrease. In essence, the mill is being used as an energy storage location, much like a steam drum, to support a rapid load increase.

-During a load increase, feeder rate and grinding pressure are adjusted simultaneously. The level of coal is only lowered temporarily. It returns to the original value for the corresponding load point once the load ramp stops. The temporary utilization of stored energy brings about the desired reduction of the boiler reaction time. The reverse process occurs in the event of a load reduction. Figure 1 illustrates how the grinding pressure of the coal mills is adjusted relative to the load.

-Distribution of the required firing load between the individual mills is no longer performed based solely on static criteria, as it now takes into account the dynamic criterion of the fireball position. Figure 2 illustrates how the SPPA-P3000 Fast Ramp solution integrates fireball control and mill grinding pressure control in the unit coordinated control structure.

-The module for controlling grinding power has now been integrated into the structure of the mill control, which also includes the modules for feeder control, primary air mass flow control, and classifier temperature control. The lower-level control structure thus automatically ensures a faster reaction capability for the boiler.

-The new SPPA-P3000 unit coordinated control structure for controlling generator power and main steam pressure provides the basis for implementation of the new modules. The unit control module coordinates boiler and turbine and outputs the appropriate load setpoints. Implementation of the extended control strategies in the lower-level control loops ensures that the boiler time constant is reduced. The unit coordinated control structure simply has to take into account that the parameters of the model contained in it are adjusted.

 

Figure 3 illustrates how the development of the electrical output of the case study plant for the same load ramps with and without the new control methods. In both cases output was increased without turbine valve throttling. The curves thus directly represent the boiler delay. It can clearly seen that these extended control methods made it possible to achieve a significant reduction in boiler inertia. In fact, the boiler time constant was reduced from the original 3.135 seconds to 3.85 seconds, a 37% improvement.

"This Article for, K. Wendelberger is director, process optimization for Siemens Energy."

STEAM TURBINE & GENERATOR ARRANGEMENT

STEAM TURBINE ARRANGEMENT

The live steam enters the HP turbine through the main stop valves (MSV) and the main control valves (GOVERNORS). After expansion in the HP turbine, the steam is let to the cold reheat line via power assisted check valve. The steam passes the reheaters of Boiler before it enters the IP turbine via the intercept stop valves (RCV) and the intercept control valves (ICV). The intercept stop and control valves are combined valves, that means stop and control valve are arranged in one common casing. The steam is let from the IP turbine to the LP turbine by the crossover pipe.  From the LP turbine the steam is fed to the condenser.

The turbine has journal two journal bearings for each rotor and one thrust bearing, of forced lubricated type.

 CONTROL  AND LUBRICATING OIL SYSTEM

The lubrication oil for the turbine bearings and control oil for the actuator positioning is supplied by Control and Lubricating oil system. During normal operation, main oil pump (MOP) driven by AC motor supplies the lubrication oil. A standby pump auxiliary oil pump (AOP) driven by AC motor supplies lubricating oil at the failure of (MOP). When MOP and AOP doesn’t work or can’t provide lubricating oil with adequate pressure, an Emergency oil pump (EOP) driven by DC motor supplies the lubricating oil. The oil discharged to supply lubrication oil for the Turbine Bearings.

Control oil is used to operate the “main stop valves, governing valves, reheat stop valves and interceptor valves” Servomotors and to operate an oil supply for trip system, this Control oil is supplied by 2 Control oil pumps (COP).

CONDENSER (HEAT EXCHANGER)

The condenser receives exhaust steam from the low pressure turbine. Circulating water flows through the condenser tubes to remove heat from the condenser, which causes the exhaust steam to condense. a sudden reduction in volume occurs which establishes a Vacuum in the condenser

The condensate steam is collected in the hotwell which is located in the bottom of the condenser. The hotwell stores the condensate for re-use and recirculation in the water/steam cycle.

The condenser is located directly beneath the low pressure turbine. As the steam exits the LP turbine, it flows over the condenser tube bundles which are oriented horizontally and perpendicular to the axis of the turbine.

GENERATOR

 Electrical Generator is the source of Electricity generated at the power plant; it is a synchronous generator whose output voltage is 19000 Volts, 50 Hz, 350 MW, with 3000 rpm.

For this big turbo generator .it is cooled by hydrogen gas for its small density, excellent cooling properties and decrease windage and ventilation loss, Also Hydrogen has large thermal conductivity and heat transfer coefficient, therefore, generator output per unit weight of active materials will increase.

Steam Turbine Systems

THIS FILE SHOWS THE DIFFERENT SYSTEMS ABOUT STEAM TURBINE, FROM ALSTOM COMPANY AT AS BUILT PROJECT IN EGYPT.

             

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Load Rejection Test (Governor Test)

The purpose of Turbine Load Rejection Test is to verify and demonstrate the governor function to sustain a load rejection in order to prevent the turbine from overspeed tripping, steady speed control at no-load operation and remain in service without any adverse effect to the turbine.

The test requires skillful and appropriate operation not only for turbine , but also for boiler and its auxiliaries.

Items to be confirmed for Load Rejection Test

1-Turbine main valves

2-GV no load valve position

3-Lube oil pump auto start test

4-Protective device test

5-Valve transfer from MSV mode to GV mode

6-Overspeed tripping point (111% speed)

7-OPC (Overspeed Protection Controller) function

8-Exclusion of Interlocks (Turbine Trip due to Boiler Trip)

TEST PROCEDURE

*Before Load Rejection Test (one hour)

1-Confirm steady condition of load operation

2-Perform mechanical Over Speed Oil trip Test

3-Perform Lub. oil pump auto start test

4-change over unit auxiliary bus from unit auxiliary transformer to start up transformer.


*Before Load Rejection Test (30 minutes)

1-Confirm that level of( Condenser , De aerator and HP/LP feed water heaters are within range

2-confirm that AVR in automatic mode

3-Confirm that HP and LP Turbine bypass ( valves and Sprays ) are in automatic mode

*Before Load Rejection Test (10 minutes)

1-confirm the appointed time with the load dispatcher

2- Exclude the interlock of (Turbine Trip due to Boiler Trip)

*Before Load Rejection Test (0 minute)

1-Open Circuit breaker of the Generator.

2-If the Overspeed trip device doesn't operate contrary to expectations even when the turbine speed exceeds 111% of the rated speed , Trip immediately the turbine.

3-All observers shall read and record "Maximum or Minimum" of the measuring objects during transient condition

After Load Rejection

Pay attention to the following points and see that there is no distinction about them.

-Turbine speed

-Rotor Position & Vibration

-BRG temp. and Vibration

-Condenser Vacuum and hotwell level

Stabilization

-Stabilization will be judged when turbine speed is stabilized approx.  3000 rpm by GV & ICV speed control

Test Acceptance Criteria

If maximum instantaneous speed is restricted below overspeed trip limits (111 %) ,therefore the load rejection test is regarded as successful.

Confirmation items after Stabilizing

-GVs are restored in no load position

-turbine speed is controlled at near synchronous level

-No abnormality is observed at electrical room and local positions.

Emergency Case

If boiler trips by boiler protection , turbine shall be immediately tripped.