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(1)IME/02 (Restricted Circulation Only). POWER PLANT PERFORMANCE. Power Management Institute Noida.

(2) CONTENTS. S.No. Description. Page No.. 1.. Introduction. 1. 2.. Cycle Efficiency. 7. 3.. Boiler Efficiency. 17. 4.. Turbine Efficiency. 34. 5.. Regenerative Feed Heating. 48. 6.. Controllable Parameters. 51. 7.. Summary. 60. 8.. Preliminary Boiler Inspection. 68. 9.. Boiler Test Procedures. 78. 10.. Efficiency Monitoring Log Sheet. 89. 11.. Turbine - Generator Heat Rate. 97. 12.. T/G Heat Rate Considering Steam flow to HPC/IPC Mass. 101. Balance and Ejector, Seals Steam Flow 13.. Coal and Ash Sampling and Analysis. 105. 14.. Centrifugal Pump Performance. 110. 15.. Liquid & Gas Flow Measurement. 125. 16.. Flow Calculations. 139. 17.. Equipment Performance. 148. 18.. Model Session Plan. 159.

(3) 1. Introduction India has a massive development programme in which thermal power generation is expected to continue to play a dominant role. NTPC has absorbed the latest technology in this field from all over the world and has created a unique- technical organization which is well on the road to attaining total in-house capability for engineering and construction of large thermal power stations with 500 MW units and EHV transmission system both AC & DC. Having acquired a position of leadership in the Power Section of the country, NTPC today is poised for making a substantial contribution in the country's power development programme. NTPC's share of 5000 MW so far has helped a lot in meeting power requirement of our developing country. NTPC's perspective plan envisages creation of 13,370 MW capacity at 1.5 super thermal power stations with associated transmission system. Considering the massive investment required for such a plan, it is important to give a thought to the returns obtainable from these stations. In order to get maximum output from given input the units must run at maximum possible efficiency and should give maximum output. Power Plant performance analysis at various steps help in improving the power generation capacity. The points that are mainly responsible for the unit/station performance are described below :1.. Planned Maintenance loss.. 2.. Thermal efficiency factors.. 3.. Plant load factor.. 4.. Forced outages.. 5.. Plant Availability factor.. Plant load factor i.e. energy generated per KW installed has a decline trend and an increased trend of various losses like forced outages and planned maintenance loss thus reduces plant availability factor. Also decline trend of 0.9% in thermal © PMI, NTPC. efficiency within. last. four years are 1.

(4) due to the low plant load factor, increase in number of start up and shut downs outages pertaining to regenerative system and variation of efficiency control terminal conditions. Thermal efficiency of the plant has also slight decreasing trend during the past few years of the designed value of the plant. Designers of plant and station were not in fact successful in optimizing the design, the engineers can still aim at obtaining the highest possible thermal efficiency even if this does not fall short of original intention. Similarly it often pays to burn a cheap and inferior quality of coal at limited combustion efficiency of boiler if the cheapness of the fuel out weight the increase in fuel consumption owing to limited combustion efficiency. This is a very important aspect of Indian scene as inferior low-grade coal is earmarked for thermal generation. It may not have been economic to build highest possible thermal efficiency into the plant nor to burn high-grade coal; the efficiency engineer can still play their role by optimizing the efficiency control conditions of the plant. Figures attached highlight the importance of need for efficiency operation of the generating unit. The cost implication due to small increase in heat rate, oil consumption, make up water consumption, excess air, condenser vacuum etc. indicate the urgent need to control these parameters within the design limit. This would lead to higher operating efficiency and corresponding saving in Cost of generation. Availability and efficiency has a direct relationship. High availability leads to higher efficiency but at the same time an efficient unit leads to better availability due to better combustion control conditions, better fluid dynamic condition and better heat transfer conditions. There exist future prospects of increasing our efficiency of thermal generation from its present maximum. This write up will be useful for the power plant engineers in improving the overall efficiency of the plant.. © PMI, NTPC. 2.

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(9) 2. Cycle Efficiency INTRODUCTION Efficiency is a word generally used to indicate the relationship between the input and output resulting from some activity. It can be loosely applied to almost any process or organization and is usually assessed by comparing the cost of the product with its actual value that is, efficient activities will produce goods or service more cheaply than similar operations carried out less efficiently. Efficiency in this broad sense could be applied to the electricity supply industry as a whole, to the administration, organizing and staffing of power stations, and to the work of individuals in carrying out their daily tasks. To have an efficient organization manned by efficient personnel is just as important to the power station industry as to any other, but in addition to this general efficiency, power stations must have thermally efficient electricity generating plant. This book deals with the thermal efficiency of generating plant, particularly from the plant operation point of view. Because the amount of fuel burnt can be expressed in heat units and the amount of electricity sent out to the transmission system can also be expressed in heat units, power station thermal efficiency is a simple ratio of the heat equivalent of the kilowatt hours supplied expressed as a percentage of the heat equivalent of fuel burnt. The precise definition of thermal efficiency for power station plant is an advantage, which few other industries possess. An overall improvement in the supply, industry's efficiency is expected every year and even a small improvement can be easily measured and recognized. On the other hand the efficiency appears to be low, as even the best stations cannot achieve more than 40 percent. It is true that efficiency is only one of several factors, which decide the cost of electricity. In particular, designers of new stations have to weigh the alternatives of extra capital expenditure against increase in efficiency and optimize at the point where increasing capital outlay would no longer bring an © PMI, NTPC. 7.

(10) increase in efficiency sufficient to justify the extra capital charges. However, once a power station is built and is generating electricity, the operators cannot do anything about the capital charges. The money has been spent and whether the station is base loaded or standing idle except for peak load, the capital charges have been incurred and must be met. If those who designed the station and its plant were not, in fact, successful in optimizing the design, the operators can still aim at obtaining the highest possible thermal efficiency even if this does fall short of the original intention. Similarly, it often pays to burn a cheap but inferior fuel at lower boiler efficiency if the cheapness of the fuel outweighs the increase in fuel consumption owing to the lower efficiency. No matter how cheap and difficult the fuel is it should be burnt as efficiently as possible. Thus, although it may not have been economic to build the highest possible thermal efficiency into the plant nor to buy 'good' coal, the plant operator can still play his part by achieving the highest thermal efficiency that circumstances permit. The increase in installed Thermal Capacity has necessitated the increase in unit sizes and parameters as well. The main incentive to go in for bigger and bigger size of units is that one expects the thermal efficiency to improve with size and the capital cost and running charges per MW to fall. The increasing trend in parameters such as pressures and temperatures is because of the reason that this increases the available energy across the turbine. The available energy is in the form of heat, which converts into mechanical energy in turbine and electrical energy in the generator. Other reasons could be: i.. The higher cost of high temperature components is partly offset by a reduction in number of components per MW.. ii.. Losses become proportionately smaller, larger the machine.. iii.. High density steam must be associated with large flows to give reasonably sized HP blades.. The steam temperatures no doubt have increased continuously but the increment © PMI, NTPC. 8.

(11) is slow as it is intimately bound up with metallurgical advances. Conceptual Study of Power Plant Efficiency Power Plant station can be divided into four component efficiencies; -. Cycle efficiency. -. Turbine efficiency (Turbo-alternator efficiency). -. Boiler efficiency. -. Auxiliary Power Efficiency (Works Power). -. Cycle efficiency being the maximum possible that could be obtained from any particular set of steam condition employed.. -. Turbine or turbo-alternator efficiency is the efficiency of turbo-alternator in converting the energy available in the cycle into electrical energy.. -. Boiler efficiency giving effectiveness of combustion and heat transfer processes to transfer heat of fuel into working fluid.. -. Auxiliary power efficiency which depends on the ratio of 'Electricity sent out' Electricity Produced'. Expressing these efficiencies as fraction and multiplying them together gives overall station running efficiency.. Efficiency of any plant or equipment is the ratio of output to its input, expressed in same physical units. Power plant is no exception. The output is the electrical energy sent out to the grid and input, the heat energy of the fuel fired in boiler. This is normally termed as overall station efficiency or overall plant efficiency thus: Overall Station Efficiency. =. Output of Station Input to Station. =. X. 100. Energy sent out (kw..hr) x 860 x 100. khjkhkhjkhjkjhkjkjkjjkjkjkkjkjkjkjkjkj Fuel burnt (Kg) x C.V. of fuel Kcal /Kg. © PMI, NTPC. 9.

(12) Where 860 is the conversion factor, which makes both numerator and denominator in same units. Also. (1 Kwhr = 860 Kcal) (1 Kwhr = 3600 KJ). The Power Plant Cycle Conventional power plants use steam as working fluid. Like all other working fluids steam also undergoes a cycle, which is known as Rankine cycle. The plot of this cycle is on a temperature entropy plane.. To constitute this plane consider heating of water at different pressures. Process 1-2 in Figure-5 is sensible heating, 2-3 is latent heating at constant temperature and 3-4 is a process of superheating which can not be achieved by ordinary heating process. This will require same form of heat exchanger. At higher pressures these processes are shown by 1', 2', 3', 4" and I", 2", 3"y 4". The stages given at 2, 2', 2", correspond 10 beginning of transformation of liquid into vapour and 3, 3', 3" correspond to the end of transformation. The locit of points marked as 2, 2', 2" is a liquids line and locit of points marked as 3, 3', 3" is vaporous line. The T-(Ø diagram so constituted will be as shown in Figure-6. It can be observed that latent heat goes on reducing with increase in pressure and becomes zero at critical point '0'. Here it must be remembered that entropy is a parameter like pressure and -temperature which when multiplied by temperature © PMI, NTPC. 10.

(13) gives the energy change in the given entropy change. For example the heat supplied to water to completely convert into steam in a process AB is given by shaded area and is equal to T1 x (Ø 1 - Ø2).. The Rankline may be split into 4 distinct operations :- (Figure-7) Water is admitted to the boiler, raised to boiling temperature and then superheated (Process F B). The superheated steam is fed to a steam turbine where it does work on the blades as it expands (Process BA). The steam is rejected to the condenser and the resultant condensate is fed bark to boiler via feed heaters. (Process AF). The turbine drives a generator, which in turn supplies electricity to the bus bars.. ENTROPY T- Ø) DIAGRAM FOR FIG-3A 'AFA’A'BA" RANKINE CYCLE Fig-7A. © PMI, NTPC. 11.

(14) These operations are shown in T - 0 diagram (Figure-7A). Some of these 4 fundamental operations are quite efficient while others are not. To understand this statement let us elaborate these paras :Para-1 This process takes place in boiler. The boiler has certain losses e.g. loss of heat through Chimney, by radiation etc. Hence a boiler is not l00°o efficient. The efficiency of boiler is the ratio of output i.e. heat supplied to steam in raising it's temperature from feed water condition. TO. superheated condition and input i.e.. the heat energy input to boiler. Thus boiler efficiency is:. Total heat of superheated steam - total heat of feed water. x. 100. Fuel burnt x Calorific value of fuel (Kcal) /kg. or mathematically =. S (hB – hF). x. 100. WxC. V. Where hg. =. Enthalpy of S.H. steam (Kcal/Kg) at B.. hF. =. Enthalpy of feed water (Kcal/Kg) at F.. W. =. Fuel burnt.. Para-2 This operation takes place in turbine. The turbine has certain fluid dynamic and mechanical losses. Efficiency of turbine can similarly be expressed as : Turbine efficiency : =. Mechanical work output (Kcal). x 100. Heat drop across turbine =. Mechanical work (Kcal) S (hB-hA). © PMI, NTPC. 12.

(15) hB and hA being enthalpies of steam per Kg. and S the steam consuming in. Kg. Para-3 The process of heat rejection in condenser which is 50 to 60% of the total available heat energy makes Rankine Cycle relatively inefficient. Cycle Efficiency. =. Energy available for conversion in work (Kcal) x 100 Energy given as heat in boiler (Kcal) or mathematically with reference to Figure-5. S (hB – hA). X 100. S (hB – hF) Heat Rejection to the Condenser A very large proportion (40-60% of total heat) is carried by circulating water. These three processes are shown in Flgure-8 on T-(D plane. The sensible heat, latent heat and super heat values are also shown in this diagram. It can be seen that 'A' in the diagram corresponds to the condition of the steam at turbine exit. Now since A lies in wet zone it will affect the last rows of moving blades by causing more erosion damage. The upper limit of % age moisture at 'A' is 12%. It will be appreciated that if pressure is increased in order to get more heat drop across the turbine, this will lead to more wetness in exhaust. This calls to for an improvement in this cycle. An improvement over this cycle is the introduction of reheating, which consists of heating the steam again in boiler after it has expanded in High Pressure Cylinder. The concept of reheating is shown diagrammatically in Figure-8A and B. This enables to increase the pressures while keeping exhaust wetness in limit. © PMI, NTPC. 13.

(16) Para-4 The conversion of mechanical energy into electrical energy in generator is relatively more efficient. The generator has certain in losses e.g. disc, friction loss, copper loss, iron loss (core loss) etc.. The efficiency of generator is =. Electrical energy sent out (kwhr) x 860 x 100 Mechanical Work (Kcal). Overall station or plant efficiency =. Boiler efficiency x turbine efficiency x Cycle efficiency x generator efficiency. At this stage it will be worthwhile to introduce following two terms which will be used quite often in discussion on efficiency aspect. Overall Turbo-Alternator Efficiency The overall turbo-alternator efficiency is the ratio of electrical energy sent out to the heat supplied to steam in boiler. OTA -. Electrical Energy sent out (Kwhr) x 860. X 100. Heat supplied to steam (Kcal) in boiler. © PMI, NTPC. 14.

(17) It can be readily seen that overall turbo-alternator efficiency is the produced of turbine cycle and generator efficiencies. It can thus be concluded that overall station efficiency Overall station/plant Efficiency =. Boiler efficiency x overall turbo alternator efficiency.. Subsequent Para No. 2 and 3 will be devoted to boiler efficiency and overall turbo-alternator efficiency respectively as these two constitute the overall efficiency of a power station. Heat Rate Heat rate is more usual way of defining and expressing overall turbo-alternator efficiency. HR. =. Heat added to steam in boiler (Kcal) Electrical energy sent out (Kwhr). Unit of heat rate is thus Kcal/Kwhr. Thus overall turbo-alternator efficiency. OTA = 860 X 100 HR Similarly overall station efficiency. OS. = 860. X 100. HR of station Here it is important to note that the station in question is in fact a boiler associated with a turbine. In case of range stations where steam turbine are fed by a common bus main from boilers the overall station efficiency should be multi© PMI, NTPC. 15.

(18) plied by an another factor known as RANGE Efficiency Factor. As range stations are uncommon these days, we will not discuss this factor further in this note. Cycle Efficiency The cycle efficiency is the maximum possible efficiency obtainable with the given cycle conditions. It is the ratio of (output) the heat available for conversion into work across the turbine to the (input) heat supplied to the working fluid. A large proportion will be lost to condenser (40 to 60% heat) making the Rankine Cycle rather inefficient.. Cycle Efficiency. =. S (hB- hA) S (hB – hF). hB. =. Total heat at boiler stop valve.. hA. =. Total heat at turbine exit.. hF. =. Feed water condition. S. =. Steam flow. (in case of reheat unit).. Cycle Efficiency. =. S (hA1 – hA2) + S’ hA3 – hA4) ———————————————————— S (hA1 – hF) + S’ (hA3 – hA2). Where h denotes enthalpies at various points in Figure-SA and S, S' Steam flows in SH and RH respectively.. © PMI, NTPC. 16.

(19) 3. Boiler Efficiency INTRODUCTION Theoretical limit of heat engine or turbine efficiency is Carnot efficiency but for boiler efficiency irrespective of steam condition the limit is 100%. In conventional power station, boiler efficiency is defined as the heat added to the working fluid expressed as a percentage of the heat in the fuel being burnt. Boiler efficiency to the greater extent depends on the skill of designing but there is no fundamental reason for any difference in efficiency between a high pressure and low-pressure boiler. Large boilers generally would be expected to be more efficiency particularly due to design improvements. Here we are listing some of the design requirement of boilers: a.. Should be able to produce at required parameters over an appreciable range of loading.. b.. Compatible with feed water conditions which change with the turbine load.. c.. Capable of following changes in demand for steam without excessive pressure swing.. d.. Reliable.. BOILER EFFICIENCY LOSSES Dry Flue Gas Loss This is the heat loss from the b0iler in the dry component of gases to the stack. The flue gas exit temperature and flue gas mass stack determines the order of this loss. This loss in a typical example can be of the order of 4.5%. a.. The excess air, which is the quantity of air, required to be fed to the boiler over the theoretically correct quantity of air needed for. Complete. © PMI, NTPC. 17.

(20) combustion of fuel, determines the extent of this loss. If too little air is supplied, the fuel is not completely burnt and if too great quantity of air is supplied the heat being carried up in the stack in greater quantities than normal. It must be remembered that nitrogen, which forms 79% of air, is merely a passenger, required fan power and carries away heat. The % oxygen at air heater inlet is directly proportional to the excess air quantity and is used as a guide to combustion conditions. We cannot get rid of excess air because it is impossible to feed right quantity of air at right time to the fuel particles in suspension. b.. Air filtration is another factor, which should be controlled to limit this loss. This factor also affects the performance of EPs and increases fan loading. Moreover boiler auto-control does not give any allowance to this air, which is infiltrating from hopper seals, inspection doors and ducts joining.. Wet Flue Gas Loss This is the loss of heat fro.-n the boiler in the flue gases due to water vapour which was present initially as moisture in the coal burnt. This heat loss is the latent heat supplied to evaporate the moisture (with some super-heating also). Typical order of this loss is 0.5%. Moisture in Combustion Loss Coal contains hydrogen, which burns to form water. This loss is the latent heat removed in flue gases by the water, which is formed by H— In a typical example this loss is of the order of 3.5%. Carbon in Ash Loss This loss is due to small amount of carbon, which remains as a residue in the ash from boiler. The loss is a function of % ash in fuel and % carbon in ash from boiler. The fineness of p.f. Influence this loss. A typical order of this loss is 1%. Here it is important to note that p.f. Fineness also affects the excess air requirement. © PMI, NTPC. 18.

(21) Radiation and Unaccounted Losses No measurement of this loss of heat from boiler is possible except that by some empirical methods. Typical value is of the order of 1%. Boiler efficiency is measured by loss method i.e. Boiler efficiency. = 100-% age losses. = 100 - (dry flue gas loss + Wet flue gas loss + Moisture from combustion loss + Carbon in ash loss + Radiation loss).. In above typical example = 100 - (4.5 + 0.5 + 3.5 + 1.0 + 1.0) = 89.5% It is important to note that incomplete combustion hence formation of CO is a big loss as can be seen from the following statement 1 Kg C burns and produces CO = Heat released 435 Btu (1088 Kcal). 1 1 Kg C burns and produces CO, = Heat released 1459 Btu (3650 Kcal). Operational Factors The losses over which the operator can exert a control are dry flue gas loss, carbon in ash loss and incomplete combustion (combustible in gas loss). a.. Dry flue gas loss - % excess air and gas temperature at air heater outlet.. b.. Carbon in Ash loss - % excess air and p.f. Fineness.. c.. Combustible in gas loss - excess air.. The boiler operation should be aimed at reducing the sum of above losses. The final gas temperature should be above flue gas dew point. It is important to remember that dew point for water vapour is not 100°C but lower than this, because of partial pressure. Most coal-fired boilers have specified air heater gas © PMI, NTPC. 19.

(22) outlet temperature of the order of 130°C being the minimum practical temperature, which is consistent with minimizing air heater corrosion. A high air heater gas outlet, temperature reduces boiler efficiency drastically. (A 22°C rise in air heater gas outlet temperature reduces boiler efficiency by 1%). Boiler operation should be aimed at minimizing the causes of high gas exit temperature, which could be due to -. Lack of soot blowing.. -. Deposits on boiler heat transfer surface.. -. High excess air.. -. Low final feed temperature.. -. Higher type of burner (+ve lift of burner angle) at low load.. -. Incorrect S/Air to P/Air ratio.. COMBUSTION CHEMISTRY Three Combustion Reactions Involving Carbon are C + 0^ —————>• CO2. (i). 2C + O2 —————>- 2CO. (ii). 2CO + 02————>2CO^. (iii). In case Wts of each element is taken in grams equation No. (i) :12+32 ————> CO2. 44 + (Heat 407 KJ released). 1 + 32 —------—> 44. + 33.92 KJ. 12. OR. 12. Similarly equation (ii) :1 gm C + 1.33 O2 —————————> 2.3 CO + 10.12 KJ © PMI, NTPC. 20.

(23) In other words, one gm—Carbon when burns as CO- produces 33.92 K3 heat and requires 2.67 gm 0- and when it burns as CO it produces 10.12 KJ and requires 1.33 gm O2. Also we know from the property of air that 1 gm O2 is present in 4.31 gm of air. or 1 gm 0- is associated with 3.31 gm N2 Therefore air required to burn: 1 gm C as CO2 = 2.67x4.31 = 11.49 1 gm C as CO2 = 1.33x4.31 = 5.75 And the product of combustion shall be: 3.67 gm CO- and 8.82 gm N2. Combustion of Hydrogen 2H,0 + 0, ———>. 2H2O + Heat released (61500 Btu/lb) 4+32 ————> 36 1 + 8 —————> 09 i.e.. O2 requires 8 times wt. of H2 and produces water: 9 times wt. of H2.. i.e.. 02 = 8H H2O = 9H. But there is one complication here. Allowance must be made for O2 available in fuel, which can readily be utilized for combustion. If we assume that all the 0, in fuel will mix with H- i.e. with l/8th of it's wt. with H2, hence the hydrogen remained in the fuel: (H- 0 Considering. H. :. Original wt. of H2 per gm of fuel.. 8 © PMI, NTPC. 21.

(24) O. :. original wt. of 0_ per gm of fuel.. C. :. wt. of Carbon per gm of fuel.. S. :. wt. of Sulphur per gm of fuel.. Combustion of Sulphur S + 02 —————> S02 Heat (9141 K3/Kg.) 32 + 32 ————> 64 1 gm of Sulphur combines with 1 gm of 0- to produce 2 gm of SO2 i.e.. 0 = S, SO2 = 2S. Theoretical O2 Required for Combustion =. 0- required for combustion of C gm Carbon.. +. 0- required for combustion of (H - 0) gm Hydrogen. 8. +. 02 required for combustion of S gm sulphur.. =. 32 /12 C +8 (H-0/8) +S. Hence theoretical air required per gm of fuel. =. 4.31 [8C + 8 (H 0) + S] 8. Where C, H, 0 and S are gm Wt. per gm of fuel. Every fuel must be treated separately when determining the theoretical air required. The convenient method is calculating theoretical air required in KG/10000 K3/Kg. G.C.V. from the table given below.. © PMI, NTPC. 22.

(25) TABLE NO. 1 THEORETICAL AIR REQUIRED S.No Fuel. Kg/10000 KJ/Kg.. Ib/10000 B t u / Ib. GCV. GCV. 1.. Bituminous Coal. 3.27. 1.60. 2.. Coke. 3.44. 8.00. 3.. Anthracite. 3.35. 7.85. /'.. Lignite. 3.21. 7.85. 5.. Peat. 3.00. 6.95. 6.. Fuel Oil. 3.21. 7.45. 7.. Nature Gas. 3.21-. 7.45. Example For bituminous coal with G.C.V. = 22,000 KJ Kg. Air required. = 22,000 /10,000 = 7.19 Kg air /Kg coal. Products of Combustion 1 gm Carbon produces 44 /12 gm CO2,. C gm Carbon produces 44 /12 C gm CO 2 per gm fuel. 1 gm H- produces 9 gm water.. (H – 0 / 8) gm H2 produces 9 (H - 0) gm water per gm fuel. Products of combustion per gm of fuel. =. 44 /12 C + 9 (H - 0 + 25 + Nitrogen (0.768 times wt. of air). © PMI, NTPC. 23.

(26) OR Nitrogen = (4.31 - 1) 32 C + 8 (H2 – 0) + S 18 Enclosed table gives the summary of the results obtained on the basis of above chemistry discussed TABLE NO. 2 THEORITICALLY REQUIRED OXYGEN FROM 1 gm OF SUBSTANCE S.No. Substance. 1. 2. 3. 4. 5.. Carbon to COCarbon to CO CO to CO^ S to SOH to H20. Theori- Theoritically tically Req. O2 Req. Air 2.67 1.33 0.57 1.00 8.00. 11.49 5.75 2.46 4.31 38.48. CO2. 3.67 1.57 -. N2. CO. SO2. HO2. 8.82 4.42 2.33 1.89 3.31 2.0 26.48 - -. 9.0. In all these equations it is assumed that available hydrogen is (H -0/8) and not H per gm of fuel, the reason being that hydrogen required 8 times 0- for combustion hence whatever 0- is present in coal the same will be exhausted within 0 /8. As far as products of combustion are concerned we have not added in the above equation any moisture produced. If 02 is C gm/gm of fuel add 9/8 (0) as water vapour produce. Also add moisture in coal and air directly. Excess Air More excess air than theoretical air is required for complete combustion. If there is a deficiency of air then some 'CO' will be formed instead of CO2 and appreciable amount of carbon left out in ash and dust. Better and through is mixing the lesser will be the excess air requirement. Too less excess air means incomplete combustion, too much excess air means large heat loss to the chimney. Optimum excess air is that which reduces the sum of these two losses to minimum. © PMI, NTPC. 24.

(27) Through mixing + proper resident time lead to optimum air Coal (a) (b). On Stocker firing. 50% excess air is required.. On PF firing 20 to 25% excess air is required.. In oil firing we need 10% excess air. The combined effect of following three-boiler losses affected by excess air is plotted in the adjacent graph (Figure-9).. 1.. Dry flue gas loss - loss of heat from chimney due to dry component of gases.. 2.. Unburnt gas loss - Incomplete combustion loss.. 3.. Unburnt Carbon loss - Carbon in ash loss.. It will be seen that there is only one value of excess air which gives maximum efficiency undoubtedly it will depend on fuel composition. Excess air is monitored by CO- and C- measurements at APH inlet. If it was possible to burn a fuel completely with only the theoretically amount of air - a perfect combustion condition, the percentage CO,, produced would be the theoretical maximum possible for that fuel as shown between in the figures enclosed (Figure-10). © PMI, NTPC. 25.

(28) Amount of excess air carried on a boiler can be calculated by using a simple formula involving maximum theoretical CO2 values and steaming CO2 values. Maximum theoretical CO2 for Carbon has been stated at 21%. Usual accepted maximum theoretical CO2 for Bituminous coal is 18.5%. CO2 reading varies with the location of the gas probe. Typical reading for a large P.F. Boiler are given in the table below : S.No.. Location of Probe. % age at M.C.R.. 1.. Combustion chamber. 16.0. 2.. Air heater gas Inlet. 15.4. 3.. Air heater gas Outlet. 14.4. 4.. ID Fan Inlet. 13.9. © PMI, NTPC. 26.

(29) Percentage CO- reading falls progressively as the flue gas passes through the heat recovery area of the boiler. Progressive fall is due to air infiltration at boiler casings, dampers, seals etc. The drop of 1% across the air heater suggests that the air heater seals are in reasonable condition. Flue Gas Analysis The method of determining the quantity of excess air present is by analysis of the flue gas. In the past it was common to do this by measuring CO-, content of the flue gas. However, the CO- indication has several limitations: i.. It is not a direct measure of excess air.. ii.. The indication is affected by the Hydrogen/Carbon ratio. For example this ratio is different for fuel oil and Coal. Thus 10% CO- means some excess air with oil firing and different excess air with coal firing.. iii.. As the excess air is reduced the CO2% increase until the CO2 is a maximum. Further reduction of excess air result in decreasing CO2. This may be interpreted that the excess air has increased.. If instead of CO2 an indication of 02 is provided then the relationship between excess air and percentage oxygen in the flue gas is almost constant whatever the type of fuel be. Oxygen analyzers are ideal for use in boiler automatic control schemes for Oxygen trim control'. With most CO- analyzers it is necessary to withdrawn a sample of gas from the measuring point for external analysis. This results in practical problems, the main two being need of cleaning of filters at the prob - end and condensation in sample carrying pipe. When burning fuel oil the permissible excess air is very low. Low temperature © PMI, NTPC. 27.

(30) corrosion at the APH can be caused by Sulphur Trioxide (SO-) in the flue gas. The dew point increases with excess air if excess air exceeds 5% with oil firing severe damage may be caused to the air heater. Preferably in oil firing oxygen in flue gas of 1/2% (half percent) should be aimed at. A recent. development is Zirconium analyzer. One such equipment has been. installed PETS in 4th Unit of Badarpur Thermal Power Station. The unit so installed consists of a: i.. Probe assembly. The sample passing over the zirconium probe across electrodes produces a voltage, which is a function of gas temperature and ratio of 02 partial pressures.. ii.. An electronic unit to convert into %02. iii.. A pump unit to provide constant reference air supply to probe.. Boiler Losses Calculations The indirect method of calculation of boiler efficiency introduced in the chapter dealing with concepts shows that: Boiler efficiency = 100— (% losses). 100 - (Dry flue gas loss + moisture loss + Carbon in ash loss +. Unburnt. gas or incomplete combustion loss + Radiation and unaccountable losses.. All losses taken as percentage heat losses :% loss = Loss per Kg of fuel X 100 C.V. Of fuel. © PMI, NTPC. 28.

(31) Dry Flue Gas Loss If W is the wt. of dry flue gases per Kg. of fuel burnt. Loss = W x C x (T - t). P Where C = Specific heat of flue gas in K3/Kg. t T. =. FD fan inlet air temperature.. = Exit gas temperature at APH outlet.. The calculation of W is done by the following relation: W = (C+5 /2.667). [ 11 CO2+8 O2+7 (CO +N2)] / [3(CO2+CO). 100. Where C and S are Carbon and Sulphur % by weight CO2, O2, CO and N-are volumetric % determined by apparatus. Unburnt Carbon Loss - Carbon in Ash Loss Imagine Kg. of fuel burning has a. =. Weight of ash per. Kg.. c.. =. Unburnt carbon % in ash. 33820 KJ/Kg. is Calorific Value of Carbon. wt. of unburnt carbon per Kg. of fuel = ac / EOC Heat loss per Kg. fuel = a x c X 33820 KJ/Kg. 100 % loss =. loss X 100 C.V Unburnt Gas Loss The weight of carbon in carbon monoxide = CO CO2 + CO © PMI, NTPC. 29.

(32) If C is the wt. of carbon burnt per Kg. fuel and heat released in burning 1 Kg. carbon in CO to CO2= 23620 KJ.. Loss per Kg. = CO. X C x 23620. CO2- + CO. KJ fuel. Kg.. Now we will discuss those losses which are not in hands of operators :Radiation or Unaccountable Losses These losses range for 110/210 MW units from 0.93% to 1% on higher side. They can be calculated by graphical methods and alignment charts. Moisture Losses Three moisture losses are: i.. Moisture in fuel loss.. ii.. Moisture in combustion loss due to H2 in coal.. iii.. Moisture in air loss.. © PMI, NTPC. 30.

(33) Heat lost per Kg. of moisture in fuel = (2477 + 2T - 4.2 t) K3/Kg. Moisture. If M is the wt. of moisture per Kg. of fuel.. i.. Moisture in fuel loss. M (2477 + 2T - 4.2 t)- KJ. fuel. Kg ii.. Moisture in combustion loss 1 Kg. H- produces 9 Kg. water. If H is the wt. of Hydrogen per Kg. fuel. Loss. =. 9 H (2477 + 2T - 4.2 t) KJ fuel. Kg.. You can observe the similarity between these two losses. iii.. Loss due to moisture in air : If Wm is the wt. of moisture in air/Kg, fuel. Loss =. mass x Sp. heat x T. Wm x 2 x (T - t) K3/Kg. fuel. This loss is insignificant hence often not calculated. Factors Affecting the Operating Efficiency of Boilers The basic principle for optimizing p.f. boiler is same as for stoker-fired boiler. The sum of the boiler heat losses plus boiler auxiliary power should be minimum consistent with maintaining full boiler availability. A fundamentally better combustion process is achieved by burning finely pulverized fuel suspended in air. The factors influencing combustion efficiency with p.f. firing is enormous. Basically they are the fineness of milled product and fuel air mixing, while burning fuel in suspension. There is optimum fineness beyond which extra mill power and wear exceeds the saving on boiler losses. © PMI, NTPC. 31.

(34) 200 mesh sleeve is used for determining required fineness (80% through 200 mesh - wires woven to inch, each wire .003" square). 100 mesh should be used for measure of reminder which will contribute to unburnt carbon loss, p.f. firing, advantages of :i.. Any grade of coal can be burnt.. ii.. Not prone to the bonded deposits.. iii.. Dust absorbs acids and thus prevent corrosion.. iv.. Reduction in boiler losses and fan power.. Disadvantage: High initial cost, auxiliary power cost and dust extraction plant. P.F. Burner Short flame turbulent burner are usually used when the firing is from the wail. Corner firing uses long flame burners firing tangentially to a vortex in the center of the furnace. Down shot burners giving a long U shaped flame are some times used for low volatile coal. In short flame burners and turbulent burner adjustments can be made to the position of the burner and to the admission of secondary air to give the best combustion for different coals. Long flame corner burner are tilted for SH and RH temperature control. Down shot burner have secondary air introduced at burners and tertiary air at various, distance along flame path. Mill Fans Agro dynamically designed P.A. Fans for use in pressure type mills are more efficient than exhausted which are built to resist wear. Cold primary air systems. are beneficial from fan power point of view. Power consumption in tube mill is about 22-30 Kwh/Ton coal milled as a gained pressure type vertical mill which consumes about 15-20 Kwh/Ton milled coal.. © PMI, NTPC. 32.

(35) Some of the Salient Features of Vertical Spindle Medium Speed Mill 1.. Low primary air quantity reduces velocity through the mill so tending to increase the fineness of milled product. The decrease of PA temperature also gives similar effect due to reduction in volume velocity PA to the mil! Table. Rejection of combustible material in reject trap is a loss hence quantity and quality of reject must be watched.. 2.. Low PA velocity causes setting of P.F. at pipe bends etc. and high P.A. velocity lifts larger particles hence affect p.f. Fineness.. 3.. The differential pressure across the mill is the measure of coal in the mill. This is a dependent parameter on P.A. differential. Classifiers can be adjusted to give the fineness of product required but should not be used to increase mill output (by vane control etc.) as this will increase unburnt carbon loss and combustion will be less efficient.. 4.. Spring loading affects the wear of the grinding elements, it may be beneficial to relax spring pressure when milling abnormally soft coal.. 5.. Equal distribution of fuel and air to the burners, particularly for wail firing will give the most efficient combustion size grading to each burner should be same. This seems to be different due to in avoidable difference in piping layout. Corner firing can tolerate some inequality between burners as turbulence exists in center of furnace. Excess fuel from one burner is compensated by excess air from other.. © PMI, NTPC. 33.

(36) 4. Turbine Efficiency INTRODUCTION This chapter deals with the efficiency of the steam turbine in converting the heat energy made available in the cycle into actual mechanical work. We have defined turbine efficiency as the ratio of mechanical work output in (Kcal) or (K3) to the total heat available across the turbine (Kcal) or (K3) expressed as a percentage. A steam basically consists of regulated quantity of steam flowing over a series of fixed and moving blades. A pair of one fixed and one moving blade is usually referred to as a stage. The stages are compounded or in other words a number of fixed and moving blade rows are kept in series to make a maximum use of the available energy by absorbing both the pressure and velocity components of steam. The compounding also results in keeping the steam velocity and rotor rpm within the desired range. A stage where all the available energy is converted into velocity in the fixed blade »s called an impulse stage. A stage where all the available energy for that stage is converted into kinetic energy in the moving blade is called pure reaction stage. In an impulse stage the steam just glides over moving blade without expansion whereas in reaction stage pressure drop is along the moving as well as fixed stage. A pure reaction stage is impractical and power Engineers mean by reaction, a stage where half the available energy is converted into KE in moving blade and half in fixed blade. The degree of reaction (R) is defined as follows :Enthalpy drop in moving blade Enthalpy drop in the stage Then the reaction turbine will have R = 0.5 (or 50% degree of reaction). Modern turbines are impulse reaction having degree of reaction increasing in the direction © PMI, NTPC. 34.

(37) of flow off steam. This particularly because the reaction stages are more prone to inter stage leakage. The chances of inter stage leakage are more on HP end and the reaction stages are more efficient than impulse stages therefore it is preferable to use HP stages as impulse to avoid leakage and of LP stages as reaction to take advantage of reaction stage. Turbine efficiency is an integral sum of stage efficiency, therefore a detailed study of stage efficiency on a Mollier chart (h, 0) will reveal many useful results. Stage Efficiency Stage efficiency is the work done on the shaft by a combination of one fixed and one moving blade expressed as the percentage of stage available energy. Or, a Mollier diagram Figure-11.. The constant pressure lines on a Mollier diagram diverge with increase of entropy. The increase of entropy is a symbol of inefficiency. In above Figure-7 if h increases, corresponding entropy will increase and stage will become inefficient. Figure-12 gives two stages. If Stage-1 is inefficient it will give more energy for conversion into work for Stage-2. Because more energy is available between any two pressures with increase in entropy, the inefficiency of one stage makes more © PMI, NTPC. 35.

(38) energy available to the next and this is known" as reheat factor.. Stage Losses One of the main cause of inefficiency of a stage is friction and eddies on the blade surface. Other factors that affect the stage efficiency are Windage Loss Windage, disc friction, or rotational losses occur because the rotors are revolving in an atmosphere of steam. The windage loss basically comes from the drag of steam on revolving blades in the steam atmosphere. The drag depends on viscosity of fluid (density increases viscosity) and linear velocity of a stage. Both HP and LP blades do suffer to the same extent owing to the fact that the latter have high linear velocity though the viscosity of atmosphere is much less. The windage loss on LP stages increases at low load thus increasing the exhaust hood temperature. Blade Length Short blades are less efficient than long blades because of interference caused by roots and tips. This is an advantage for high rating turbines at HP stages. © PMI, NTPC. 36.

(39) Partial Admission Loss Steam regulation at turbine inlet are done in two ways. Throttle governing, where all control valves operate simultaneously and nozzle governing where control valves operate in a sequence. Blades directly opposite to the nozzle block are running full of steam but the blades away from nozzles will produce eddies and extra losses. This loss which is found in nozzle controlled turbines due to steam being admitted around part of the periphery only is known as partial admission loss. Interstage Gland and Tip Clearance Loss The reaction stages there is a pressure drop across the moving blades and the clearance between them and the casing is sealed by providing radial or axial seals. Inter stage seals are also provided between root diaphragms and the rotor. If gland leakage annulus area is 1% of blade area the steam flow through gland will be 0.2 to 0.5%. Loss of efficiency due to this leakage 0.3 to 0.75% (i.e. 50% greater than actual leakage because of turbulence and disturbance in main steam path). This loss depends on shaft and blade sizes and type of labrinth used. Normal value for modern turbines is between 1/3 to 1%. One bad start with eccentric shaft causing rub could easily increase clearance to large extent incurring heavy efficiency Joss.. External Gland Loss External gland leak off also causes of available energy but this loss is not 1% for every 1% leakage because same heat value of leak off is utilized in Gland steam coolers with and without ejectors. Low-pressure gland leak off is sucked by gland steam cooler with ejector which* also forms a part of regenerative feed heating system. Wetness Loss Wet steam causes a loss of stage efficiency of 1% for every 1% water because of © PMI, NTPC 37.

(40) the water droplets lagging behind the steam and thus reducing the efficiency with which energy conversion takes place. This is one of the important cause of erosion which permit to restrict moisture to 12% in last rows of LP. Leaving Loss The KE of steam represented by residual velocity of steam leaving the stage is known as leaving loss. It is the energy which cannot be practically converted into mechanical work. Turn Up Loss and Exhaust Hood Pressure Drop These two also constitute the part of exhaust losses of which leaving loss is pre measure factor. Turn up loss occurs at low steam flows. It is because of the fact that last stages become progressively less efficient as steam flow fall below 30% MCR. This exhaust overheating may require hood sprays. Exhaust hood pressure drop is also a loss of available energy amounting to the difference between the energy level (enthalpies) at condenser and IP turbine exhaust. Mechanical Losses Mechanical losses are bearing losses plus power required to drive oil pump and governors. They are constant irrespective of load. Additional Notes a.. More correctly a stage is defined as the number of times the pressure is broken in the fixed element, fixed blades or nozzles.. b,. Stage efficiency is a function of the ratio, steam velocity/blade velocity. The efficiency of any stage except, the last (and the first in case of nozzle governed machines) remain sensibly constant over a very wide range of steam flows. These two exceptional stages work with a variable pressure ration hence they have variable efficiencies.. © PMI, NTPC. 38.

(41) c.. Minimum losses are used by reversible processes, that is fluid flow without pressure drop and heat flow without temperature drop; therefore degradation of pressure and temperature should be avoided where possible.. d.. Pressure drops anywhere in the steam path cause a loss of available energy and thus cause a loss of efficiency. Pressure drop can take place at control valves (5% even when C.V. are wide open). Pressure drop takes place in bled steam pipes (as high as 10%).. Now we will study the factors affecting the operating efficiency of turbo-alternator. Factors Affecting the Operating Efficiency of Turbo-Alternators In earlier chapter we have defined the three types of governing as follows. Throttle Governing All first stage nozzles are in common annulus and are subjected to the same amount of throttling. Nozzle Governing Each governor valve controls a separate group of 1st stage nozzles, it minimizes throttling loss at part load. There is another type of governing known as over load governing in which steam is admitted after some stage for peak loading. The operating efficiency of a turbine alternator depends on many factors such as load, terminal conditions etc. The load is a factor, which determines the amount of throttling at the control valves, and thus contributes towards loss of efficiency, depending upon the type of governing.. © PMI, NTPC. 39.

(42) Effect of Load With governor valves wide open the flow through the turbine is as high as possible. To make it higher. the. steam. pressure before. governor. valves. have to increase. A 10% increase in absolute pressure will give 10% increase in steam flow through wide-open control valves and 10% increase in output. To reduce load, the flow is to be reduced. To reduce flow by 10% the throttles must be closed until the after throttle pressure has been reduced by 10%. Not only after throttle pressure is proportional to steam flow but also pressures at subsequent stages are also proportional to steam flow except pressure at exhaust decided by condenser. This pressure flow relationship is applicable to throttle governed turbines. With overload valve governing this is applicable from overload belts onwards. With nozzle-governed turbines this relation is applicable after few stages. Unless some change occurs in the area of the steam flow paths through the turbines stage pressures are proportional to the rate of flow of steam to the following stages. It can be concluded that throttle governing is a simpler system and would probably give better efficiency at full load than nozzle governed set. HP cylinder can by symmetrical and should heat up symmetrically as steam is admitted ail around the circumference of the first stage. With off nozzle control governing, the first stage operates with a pressure ratio which varies with load. As a result the efficiency of the first stage is variable, but at part loads the turbine would have a better efficiency than a basically similar throttle governed set.. © PMI, NTPC. 40.

(43) Any loss of pressure due to throttling at the Turbine inlet causes a loss of efficiency. It can be seen from Figure-13 that :BE. <. AD. CF. <. AD. Now for a reheat machine the reheated pressure also drops with throttling in the same proportion (unlike condenser vacuum). Therefore in HP cylinder the enthalpy at inlet and outlet remain practically unchanged. Loss of available energy will certainly be there in IP cylinder and LP cylinders because of increase in enthalpy of exhaust with entropy increase. Thus the net effect is :. Loss of available energy, which is due to throttling, is not as great for a reheat set as for non reheat set. Moreover enthalpy at reheater is high because reheat temperature is controlled (TC lines are slopping upwards whereas HC lines are horizontal). Thus the loss after reheater is not as great as it is thought so far in the discussion. Terminal Conditions Terminal conditions are all important in obtaining best efficiency particularly SH, RH temperature and vacuum. © PMI, NTPC. 41.

(44) Effect of Vacuum It is established in earlier chapter that vacuum has largest effect. The leaving velocity is proportional to the specific volume. The rapidly with improvement in vacuum. The gain. specific. in. volume. available. increase. energy due to. higher vacuum is partly offset by the increase in specific volume. hence to. exhaust losses. The turbine manufacturer curves should give some indication. This turning point is well below the reach even with coldest CW water in winter. A separate lecture will cover condenser performance. The terminal. temperature. difference (TTD) which is defined as the temperature difference between steam in saturation to outgoing CW water is infect a measure o*f it's log mean temperature differential (LMTD). A high value of. TTD. is an. indication. of. contamination of CW side of the tubes by slime and dirt, and also that of air ingress ih steam space. Under cooling of the condensate is due to air leakage only therefore this temperature differential is also of importance. Because of partial pressure of the air at the bottom of the condenser the condensate temperature is lowered -below that corresponding to total pressure, since it is corresponding to the partial pressure of the steam only. Main thing to realize is that when there is air ingress the heat transfer co-efficient becomes poor therefore temperature differential increases by way of increase in condensing temperature in order to get heat across air barrier. This makes the vacuum worst. EFFECT OF MS AND RH PRESSURE TEMPERATURE Temperature MS and RH For a non-reheat machine the design philosophy is to select highest steam temperature feasible at the time coupled with pressure, which gives required exhaust wetness (limit for erosion 12%). A fall of TSV temperature for a non-reheat, machine reduces the available energy and increases exhaust wetness and possibly more erosion damage to LP blades. TSV temperature for a reheat machine is of equal importance but has the effect on exhaust wetness. More heat will have to be supplied by RH and heat loading © PMI, NTPC. 42.

(45) on SH will reduce. Thus it can be concluded that effect of MS temperature on Non-reheat and reheat machines is of equal importance except that the effect on exhaust wetness is negligible in case of reheat set Effect of reheat temperature is also significant but it does not effect expansion in HP cylinder. Pressure MS and RH In nozzle governed machines it is important that a full pressure should be maintained at part load and for throttle governed machines it is recommended that the pressure should b( reduced at TSV to reduce throttling loss at part load. It can be seen from Figure-14 that if the TSV pressure is not controlled in case of throttle governed machines there will be some increase in entropic heat drop (A'B' - AB) thus throttling loss is compensated partly.. There is a definite advantage in sliding pressure operation of throttle-governed machines. This reduces the losses due to throttling at part load because the © PMI, NTPC. 43.

(46) control valves are kept wide open. This is a good practice so long as the protection of super heaters and reheaters is taken into account. At a turbine trip there will be no flow through them for a long time till safety valves operate. This may give rise to tube failure due to starvation. Reheat pressure drop is a significant loss but there is little, operating staff can do about it except take it into account when comparing one unit with another. It can be confirmed from the Figure-15 that F'H' is greater than FH, because of the fact that constant pressure lines diverge outwards.. © PMI, NTPC. 44.

(47) Effect of Heater Efficiency Like other heat exchangers the heater efficiency is also measured in terms of TTD. Desuperheating section are provided on heaters to reduce TTD and drain coolers to reduce the losses due to flashing of drain of next higher heater in the heater in question. The terminal temperature difference of each heater should be regularly checked. The loss of efficiency which is due to poor heater performance is approximately 0.015% for each 1°F increase in TTD for all heaters, FCNRVs should be having wide opening and freedom to move. Gland Wear Gland wear is one of the causes of turbine depreciation and most of it occurs in a rough start. Strict watch is needed on turbovisory reading. Feed Pump Power The power required by the feed pump rises as. the cycle pressure rise. The range of power consumption in BFP is from 1.5% to 2.5% of turbine output for most of our units. However this feed pump power is not a total loss as most ol it goes as heat into the feed water. Note : Plotting rate of steam flow or hourly heat consumption against load gives a straight line which is known as Willans Line (Figure-20) in next chapter. The slope of this line is heat rate. The no load steam consumption is simply an intercept of this line on no load axis and does not mean that it is no load steam consumption. The value of this intercept is: 5% to 8% on throttle governed machines, 2% to 5% on nozzle governed machine. © PMI, NTPC. 45.

(48) Turbine Testing - A Brief Note Acceptance tests on turbine plant normally covers the following: 1.. Heat rate at various loads.. 2.. Condenser performance.. 3.. Feed heater performance.. 4.. Governor performance etc.. Heat rate test at full load will also serve' to demonstrate that the turbine is capable of generating it's specified output under the specified conditions effect of change of terminal conditions on Heat rate is established by experimental method and also by mathematical modelling. This effect is included by calculating percentage heat rate correction factors as shown in a series of figures enclosed. Net Unit Heat Rate =. Heat supplied to Working fluid in Boiler (KWH). - (KWH). Total. Auxiliary Cons.. Actual heat rate = NUHR X Various correction factors. For a reheat unit : Numerator of NUHR. S (Heat supplied per kg. from FFT to SH outlet temperature). + S’ (Heat supplied per kg. in. reheater). Where S and S' are steam flow in SH and Reheater S' = S - (Extractions from HP turbine and CRH). The steam flow S is measured by indirect method as follows :i.. Main test venturi on feed line will give Feed Water flow to boiler M1.. ii.. Variation in level of various heaters is measured and the sum of all. © PMI, NTPC. 46.

(49) level changes will give total gain or loss of water from system M1. iii.. Turbine throttle flow = M1. – M2.. The total heat supplied in boiler up to 5H and in RH is read from steam table/ nolliar diagram as enthalpy. (K3/Kg.).. © PMI, NTPC. 47.

(50) 5. Regenerative Feed Heating INTRODUCTION The regenerative cycle has a higher thermal efficiency than the basic Rankine cycle and the improvement increases as the number of feed heating stages increases. Each additional heater adds a progressively smaller increment of efficiency and theoretically an infinite number of heaters will raise the efficiency of the regenerative Rankine cycle to The Carnot efficiency. This may be simply shown by considering the saturated steam cycle illustrated in the series of temperature entropy diagram of Figure-16. As the number of feed heaters increased there is a progressive increase in cycle efficiency, measured by an increase in the ration of areas of useful work and heat supplied.. Figures-16A shows the basic Rankine cycle with wafer heater only in the boiler. The carnot cycle diagram for the same steam conditions in super imposed and indicates the maximum efficiency (that is the greatest area of useful work) that can be achieved in any power plant operating between the temperature T, and T— In the ideal Carnot cycle the heating of feed water from condenser temperature to boiling point has been shown as reversible in entropic progress, but this can never occur unless temperature differences, causing heat flow are kept (impossible) at zero. The water heating process of the more realistic Rankine cycle involves an increase in entropy and therefore reduces the efficiency of the cycle compared with that of the carnot cycle. The temperature difference between the hot gases in a boiler and the water being heated is far from zero and the © PMI, NTPC 48.

(51) irreversibility of this water heating process is readily apparent.. Figure-16B shows a regenerative cycle, operating between the temperature T. and T- as in Figure-9, with a single feed water heater extracting steam that was expended half way through the turbine. The steam heats the boiler feed in a direct contact heater from 1- (Condenser temperature) to T. the temperature of the steam at the turbine bleed point, assuming no loss in temperature in the bled steam pipe or heater. The quantity of steam extracted expressed as a fraction of the total flow, it is appropriate to regard BC as the steam flow to the turbine or the quantity circulating in the cycle in pound per hour and the area ABC Y x E therefore the useful work done each hour. Similarly AE is the quantity of steam rejected to the condenser in points per hour and the energy lost from the cycle per hour is represented by area AEFG.. © PMI, NTPC. 49.

(52) Figure-16C and 16D show regenerative cycles also operating between temperatures T. and T- with three and seven stages of feed heating, drawn to the same scale as the previous diagram. It will be noted from 16C that the steam quantity XY tapped by Heater-1 heats the feed from T- to T., the steam quantity pq tapped by Heater-2 heats the feed from t to t-, the steam quantity uv tapped by Heater-3 heats the feed from ty to t, and that the feed temperature rise in each heater is equal. Similarly the seven stage feed train shown in Figure-160 has equal temperature rises across each heater and the final feed water temperature t, is close to T. the saturation temperature of the cycle.. As more and more steam has been extracted from the turbine for feed heating by the increasing number of heaters it is seen that the useful work area in Figure-168, C&D has been progressively reduced. However, the energy lost to the condenser (heat rejected from the cycle) has been reduced at a greater rate so there is an improvement in cycle thermal efficiency as extra heaters are added. The above can be summarized as follows:. Regenerative feed heating improves the efficiency of cycle. After expanding part of the way down the turbine some steam is bled off to heat the feed water returning the boiler. This bled steam does same work in turbine and then rejects heat to the feed water so reducing amount of heat which would have been rejected f''om the cycle (40 to 60%) in the condenser, to the heater it will give at least 90-95% heat thus improving efficiency.. © PMI, NTPC. 50.

(53) 6. Controllable Parameters The controllable parameters in the unit operation for both turbine and boiler section are : Steam Temperatures. MS and RH. Steam Pressures. MS. Final Feed Temperature Condenser Vacuum Carbon in Ash % Oxygen at air heater inlet Flue gas exit temperature (APH outlet) Apart from this the controllable station parameters are Make up Works Units. CONSIDERATION OF EFFICIENCY CONTROL PARAMETERS Back Pressure of Vacuum So far as efficient running of the unit is concerned, condenser vacuum is probably the most sensitive terminal conditions. The heat rejected in the thermal cycle depends upon the vacuum as it is equal to the product of absolute temperature (which depends upon mvacuum) and change in entropy (during condensation). For higher cycle efficiency higher vacuum is required, but the increase in vacuum leads to increase in leaving and exhaust losses. Thus, there are two conflicting requirements and an optimum value for vacuum may exist as shown in Figure-17. © PMI, NTPC. 51.

(54) But in practice, particularly, in Indian due to atmospheric conditions, the vacuum conditions where diminishing returns start do not prevail and hence operator is always required to maintain good vacuum.. The usual reasons for departure of condenser conditions from optimum are one or more of the following ; Cooling. water. inlet. temperature. different. from. design.. Cooling water quantity following through condenser incorrect. Fouled tubes and plates. Air ingress into system under vacuum. The air ingress into the -system can be checked by starting stand by ejector, if the performance improves it shows the existence of leak in the system. Under this condition the condensate will also the under cooled. It may be remembered that running of additional ejector constitutes loss and hence air leak points shall be detected and sealed. Steam Pressure at Turbine Stop Valve The effect of variation in pressure can be studied in the following way for a throttle governed turbine (Figure-15). Supposing the unit is running at full load and the pressure at TSV increases. The effect of this will be that control valves will tend to close to suite the new pressure load condition thus the steam will be throttled. This will result in lower temperature, lower is entropic drop and higher wetness at exhaust, all factors leading to lower efficiency. The increase in wetness can cause erosions of blades at the last stage. © PMI, NTPC. 52.

(55) In case the pressure falls when the unit is on part load, to meet the new conditions control valves may further open thereby reducing the throttle, hence the effect will be opposite to that given in above para i.e. an increase in efficiency. Thus the operation on low pressure may look to be advantageous in the first instance. But further, considerations will show that reduced pressure may look to be advantageous in the first instance. But, further, considerations will show that reduced pressure w41 effect the .regenerative system which will require more steam at extractions. Similarly when the unit is on full load the fall in pressure will require more steam both in terms of weight and volume to be admitted , provided that control valves have the capacity, otherwise load will fall. It may also be remembered that cycle efficiency is higher at higher cycle conditions. Final Feed Temperature The lower final (i.e. at economizer inlet) feed water temperature denotes the inefficient functioning of feed water heater(s) or non-functioning of some from the chain. The introduction of regenerative system has been done to increase the efficiency of cycle and thus if its most important component vis. Heaters do not work effectively upto the designed parameters, the desired efficiency of cycle and hence of plant will not be achieved. Lowering of final feed temperature will also result in increased boiler firing rates. This will upset the heat absorption balance between various surfaces making steam temperature control difficult and resulting in high steam temperatures at outlet of exit super heater. To check the performance of a feed water heater it is necessary to compare the following figures with the design values for the particular load on turbine. a.. Bleed steam inlet pressure and temperature.. b.. Drain water outlet temperature.. C. Feed water inlet temperature.. d.. Feed water outlet temperature.. © PMI, NTPC. 53.

(56) e.. Feed water temperature at economizer inlet or feed regulating station.. The Excess Air The excess air which is the quantity of air required to be fed to the boiler over the theoretically correct quantity of air needed for complete combustion of fuel, determines the extent of this loss. If too little air is supplied, the fuel is not completely burnt if too great quantity of air is supplied the heat by being carried up in the stack ion greater quantities than normal. It must be remembered that nitrogen which forms 79% of air is merely a passenger, requires fan power and carried away heat. The % oxygen at air heater inlet is directly proportional to the excess air quantity and is used as guide to combustion conditions. We cannot get rid of excess air because it is impossible to feed right quantity of air at right time to the fuel particles in suspension. Air infiltration is another factor which should be controlled to limit this loss. This factor in addition to lowering of boiler efficiency due to cooling effect on gas also affects the performance of ESP and increases fan loading. Moreover boiler auto control does not give any allowance to this air which is infiltrating from hopper seals, inspection doors and ducts joining. Air Heater Gas Outlet Temperature The last heat exchanger in a gas circuit is the air heater. On one hand it will be desirable in the interest of overall efficiency that these gases leave air heater etc. the lowest temperature on the other hand this temperature is required to be high on account of corrosion problems. The flue gas in addition to carbon dioxide contains water, vapour, sulphur-dioxide and chlorides. In case the metal temperature is below the dew point, water vapour will be formed which will combine with constituents to form sulphuric acid. Due to the fact that partial pressure of vapor in flue gases is less than atmospheric its dew point may be below 100°C. Most coal burning boilers have specified air heater gas outlet temperature of the order of 130°C as being the © PMI, NTPC. 54.

(57) minimum practical temperature which is consistent with minimizing air heater corrosion. The air heater gas outlet temperature if higher the optimum value will lead to increased heat loss. For every 2°C above optimum each Kilogram of dry flue gas carries approx. 2.5 K3 of extra heat up the stack. A rise in air heater outlet temperature of approx. 22°C will reduce the boiler efficiency by about 1%. Excess air, low feed water temperature, deposits on boiler and air heater heat transfer surfaces, shortage of air heater plates (in rotary type), defective soot blower operation and using higher tier burner on low load etc. are some of the causes for higher gas temperature at outlet of the air heaters. Combustible Material in Ash The main loss is due to the unburnt carbon in the ash and is expressed as a x c x 33940 K3 / Kg. of fuel 100 Where a c. = Weight of ash/Kg, of fuel. = % combustible matter (i.e. carbon in the ash).. A small amount of combustible material amounting to about 1.5% of ash can usually be tolerated. It may be uneconomical even to remove all the combustible as mill grinding power may have to be increased or its output reduced. The grinding is considered to be in order if the PF through 200 mesh is 75% for bituminous coal or 85% for low volatile coal. The various causes of high carbon in ash are :Coarse grinding. Mal adjustment of flame. Unequal loading of different mills particularly in direct firing system. The incorrect combustion air temperature. Lower temperature may cause © PMI, NTPC. 55.

(58) condensation and higher temperature carrying both resulting in blocking of coal pipes. Suitable coal temperature range in 65 - 82°C at mill outlet. Make Up Water The amount of make up depends upon the leakage and the quantity of heat lost depends also on the point of leakage. Naturally leakage of steam is more costly as compared to leakage of water in the system. The normal sources of leakages are due to soot blowing and blow down operations. The amounts of heat lost at different locations are as under ;Leakage from condensate pumps entails a loss of 45 to 70 K3/Kg. For non reheat turbine leakage from TSV will mean a loss of 3025 to 3260 K3/Kg. The % loss of steam at full enthalpy will cause a heat loss of 1 .2%. In case of reheat units it may be of the order of 1.0 to 1.5%. 1% loss of water after final feed heater cause about 0.4% heat loss. 1% of soot blowing causes 0.8% of heat loss. 1% Blowing down may cause 0.25 to 0.5% heat loss. During starting metal and silica pick up is higher. The amount of Blow down has to be increased under the advice of Chemist, thus heat loss may also be more.. The parameters being also low at start thus the heat loss per Kg. will be a bit less, thus it is the quantity of blow down which is the cause of increased loss. Works Power Every Megawatt that can be saved on works power becomes available to the system thereby improving the efficiency of the station and the grid. As the load demand falls the works power also falls, but not in the same proportion i.e. percentage of works power will be more on low station running load Figure-18. © PMI, NTPC. 56.

(59) We can take a number of steps to improve the situation few of which are given below:. The station loading must be such that sufficient load is available to justify the operation of second auxiliary. Wherever variables speed drives are available, attempt should be. TO. run these at. the lower speeds commensurate with the load. In the milling plant attempt should not be made to over grind the coal. The fineness of PF should be kept to optimum value. Higher fineness means more grinding power mills to be run. Pumps which are liable to accumulate air and have no automatic venting arrangements should be vented regularly. Trapped air increases power consumption, a case in point is the performance of cooling water pumps.. © PMI, NTPC. 57.

(60) The Unit Loading The efficiency of a plant depends upon the load. Every machine is designed for a maximum efficiency at a particular load coiled 'Maximum Economic Continuous Rating (MECR)' which is quite different from 'Maximum Continuous Rating (MCR)'. Now the difference between M£CR and MCR is not sharp as the turbines give lowest heat rate of unit maximum loading. The curve of Figure -19 shows variation of unit efficiency with loading. A lot of heat consumption VS load is Willan’s line and gives incremental heat as it’s slope Figure 20.. © PMI, NTPC. 58.

(61) The efficiency of most boilers reaches a peak at about 80% MCR and then falls. This means boiler shall be limited to 80% MCR, but in practice it is not possible, keeping in view the load demands and efficiency of turbine being high at higher loads. The boilers have some over capacity to meet demands when one of HP heater is off, thus even when unit is on full load, the boiler may be nearer to MCR.. © PMI, NTPC. 59.

(62) 7. Summary 1.. The cycle efficiency is the theoretical ideal efficiency for a given set cf terminal conditions, i.e. initial steam pressure and temperature, reheat pressure and temperature, vacuum and final feed temperature.. 2.. Cycle. efficiency. (percent). =. available. energy. x. 100. heat added 3.. Available energy. = work that could be obtained from the cycle = heat = heat added - heat rejected. 4.. The heat content of water is called sensible heat. The heat required to evaporate water is called latent heat. The heat required to raise the temperature of steam above its evaporation temperature is called superheat.. 5.. Regenerative feed-water heating improves the efficiency of the cycle. After expanding part of the way down the turbine some steam is bleed off to heat the teed water returning to the boiler. This bleed steam does some work in the turbine and then rejects its heat to the feed water so reducing the amount of heat which would have been rejected from the cycle in the condenser, thus improving the efficiency.. 6.. The Carnot cycle gives the maximum efficiency that can be obtained by any heat engine working between an upper and a lower temperature.. Carnot cycle efficiency. T1 – T2 T1. © PMI, NTPC. 60.

(63) 7.. Where T,. = upper temperature in "Kabsolute.. T2. = lower temperature in "Kabsolute.. Providing it does not jeopardize boiler availability, optimum boiler efficiency occurs when the sum of the auxiliary power and the heat losses are at minimum.. 8.. Increasing excess air should reduce the unburnt carbon loss, but increases the dry gas loss.. 9.. As the efficiency of a given, boiler is dependent on the fuel being burnt, the best assessment of fuel cost is on the basis of heat to the turbine, i.e. heat cost of fuel divided by the boiler efficiency.. 10.. A fundamentally better combustion process is achieved .by burning finely pulverized fuel suspended in air.. 11.. Short-time turbulent burners are usually used when the firing is from the wall. Corner firing uses long-flame burners firing tangentially to a vortex in the center of the furnace. Down-shot burners giving a long U-shaped flame are sometimes used for low-volatile coal.. 12.. Primary air fans for use in pressure-type mills and more efficient than exhausters on suction-type mills so that milling power will be less with pressure-type mills. The tub a mill is much heavier on power consumption than either the ring ball mill or the bowl mill.. 13.. Low primary air quantity reduces velocity through the mill so tending to increase the quantity of rejects and increase the fineness of product.. 14.. The differential air pressure across a mill is a measure of the coal in the mill.. 15.. Classifiers can be adjusted to give the fineness of product required but should not be used to increase mill output as this will increase the unburnt. © PMI, NTPC. 61.

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