ENERGY_PERFORMANCE_ASSESSMENT_FOR_EQUIPMENT_AND_UTILITY_SYSTEMS_(CHAPTER-11:ENERGY PERFORMANCE ASSESSMENT OF THERMAL POWER STATION)

 

ENERGY PERFORMANCE ASSESSMENT FOR EQUIPMENT AND UTILITY SYSTEMS 

(CHAPTER-11:ENERGY PERFORMANCE ASSESSMENT OF THERMAL POWER STATION)

Introduction

Coal fired thermal power plants generate major portion of India’s electricity. In a typical thermal power plant the raw coal is crushed and pulverized in a mill to a size finer than face powder. The primary air supply dries and transports the coal into the boiler furnace. The coal burns in the furnace to generate superheated steam which drives a turbine connected to an alternator to generate electricity.

The components of a typical power plant are depicted in the Figure 11.1.

The power plants operate on a modified Rankine cycle with reheat and regenerative systems.

Reheat

Reheating the steam after it has partially expanded through the turbine increases the average temperature of heat addition and cycle efficiency. For a typical 210 MW power plant, (Figure 11.4) major part of the superheated steam from HP turbine exhaust at 36 kg/cm’, at around 336 °C is brought to the reheat section of the boiler, where the temperature is raised to approximately the main steam superheat temperature of 535 °C. The hot reheat steam is then returned to the intermediate pressure turbine to complete its expansion. This helps in extracting greater amount of work from the steam.

Figure 11.2 shows the equipment arrangement and the 7-S diagram for the single reheat cycle. The additional work as a result of reheating is shown by the shaded area bounded by points 4-5-6-6’. The

additional unavailable heat that must be rejected is shown by the area bounded by b ‘ - 6 ‘ - 6 - b. The

gain in net work, therefore efficiency, is realized as the heat added, is greater than the additional heat

rejected. Among other advantages, this prevents the vapor from condensing during its expansion which

can seriously damage the turbine blades.

Regenerative Feed Water Heating

In a typical power plant cycle shown in Figure 11.3 the regenerative portion utilizes partially expanded

steam extracted from the turbine at various points to heat the condensate and feed water through HP/ LP heaters on its way back to the boiler or steam generator. A part of the steam (Figure 11.4) is drawn at 36 kg/cm? from the high pressure (HP) turbine and at 16 kg/cm’ from the intermediate pressure (IP) turbine for the HP heaters. For the LP heaters the steam is extracted from various stages of low pressure (LP) turbine. In large power plants as many as eight stages may be employed. What this means is that incremental steps of heat transfer to the feed water increases the cycle efficiency as against having the entire heat transfer taking place within the boiler.

Increasing the average temperature of heat addition can also be accomplished by increasing the

temperature of the feed water entering the boiler. To realize a gain in efficiency, heat from within the

cycle is used to elevate the feed water temperature. This can be done by extracting a portion of the

partially expanded steam from the turbine and directing it to a heat exchanger that heats the feed water

to the boiler. This process is called regenerative feed water heating.

Purpose of the Performance Test

The purpose of the performance test is to arrive at the efficiency parameters for the power plant as a whole and also the various components of the power plant.

Performance Terms and Definitions

This section gives a brief detail of various performance parameters dealing with the power plants.

Overall efficiency

The term “overall efficiency” as defined solely for power generation only considers the useful electrical output to effective heat input to the power plant. Therefore, the equation for efficiency is

The overall efficiency of power plant can also be determined from Qc as follows

Specific fuel consumption

Major Area/Equipment in Thermal Power Plant

The major areas for conducting performance test in thermal power plants are:

¢ Fuel handling system and preparation (E.g.: Coal handling system and coal mills)

¢ Boilers and its associated parts

¢ Turbines and its associated parts

¢ Draft system /Fans (ID fans, FD fans, PA fans and other fans.)

¢ Condensers

¢ Water pumping systems (Boiler feed water pumping system, Condensate extraction pumping

system, DM water pumping system, Make up water pumping, Raw water pumping system, etc).

Table 11.1. Typical auxiliary power consumption in power plant

Table 11.2. CERC norms (2014-19) for Auxiliary Energy Consumption of coal-based generating

stations

Coal Handling Plant

Coal handling plant is one of the important energy consumers in thermal power plants and contains

the following energy consuming equipments.

1. Crushers

2. Conveyors

3. Feeders

4. Tipplers

The major objectives of coal handling plant energy audit are

« To evaluate specific energy consumption of the CHP equipments (kWh/ton of coal)

« To evaluate percentage power consumption of CHP with respect to total auxiliary power consumption

« To analyse the crushed coal size and rejects

Performance measurements

= Carry out power measurements of conveyors, crushers and feeders etc. In the absence of energy

meters, take readings from on-line panel instruments for current, voltage, power factor etc., portable instrument can also be used for power measurements.

«The coal flow rate can be recorded using weigh feeders.

Table 11.3. Typical specific energy consumption of the CHP

Table 11.4. Auxilliary power consumption of CHP

Performance of Crushers

1.Observe and compare the operation of crushers and their throughput, hours of operation, specific power consumption, etc

2.Carryout the size analysis and compare with the design or optimum values 

3.If significant proportion of coal >20 mm size is observed on the downstream of crusher, it may lead to substantial increase in power consumption of coal mills.

Coal Mills

The major objectives of coal mill energy audit are

1.To evaluate specific energy consumption of the mills. (kWh/ton of coal)

2.To establish air to coal ratio of the mills (ton of air per ton of coal)

3.To perform heat balance of the mills

4.To analyse the coal fineness and mill rejects

Performance measurements

1.Carry out power measurements of mills, PA fans, seal air fans, etc,. In the absence of energy

meters, take readings from on-line panel instruments for current, voltage, power factor etc. For

LT equipment, portable instrument can be used for power measurements.

2.Coal flow to be established by dirty Pitot tube test (to be carried out on Pulverised coal lines).

This also helps to identify unbalancing/choking is occurring in flow in the Pulverised Coal

lines. The on line coal flow values if available, may also to be taken by appropriate coal feeder

calibration.

3.Airflow to be established per PA fan by clean air Pitot tube method.

Air to coal ratio of the mill

Specific energy consumption of the mill

Example 11.1. Determine the air fuel ratio and specific energy consumption of mill from the following data

Coal flow rate = 48.64 TPH

Air flow rate = 112.6 TPH

Energy consumption = 351 kW

Mill Heat Balance

Schematic of mill heat balance

Primary air — used for drying and conveying the coal, Seal air — pressurised air used to seal the motor shaft of coal mill to avoid leakage.

Example 11.2. Coal Mill Heat Balance

Total PA flow = 112.6 TPH

Inlet PA temperature = 243 °C

Seal air flow = 2.0 TPH

Seal air temperature = 50°C

Coal flow rate = 48.63 TPH

Power consumption = 351 kW

Air and coal mix flow = 161.23 TPH

Air and coal mix temperature = 65.5 °C

Ambient temperature = 35°C

Reference temperature =0°C

% Moisture removed = 8071 / 48630

= 16.59 %

Analysis of mill fineness and mill rejects

For a typical PF coal fired boiler, over 80% of fine coal should pass through 200 mesh for good combustion efficiency. Mill performance is monitored by fineness of mill output at regular intervals and when there is a fall, maintenance practices are reviewed.

Mill rejects

Mill rejects are an indication of mill performance. It is desirable to carryout the detailed analysis of mill rejects (table 11.5), compare with the other mills and coal quality. The variation in mill rejects (among the mills) could be due to variation in performance of mill due to mill internal status, fuel handling, etc.

Table 11.5. Mill rejects reporting

Boiler

Schematic diagram of a utility boiler

The brief specifications of a typical boiler used in 210 MW plant is given in the table 11.6.

Table 11.6. Typical boiler specifications for a 210 MW unit

Performance evaluation of economizer and air preheater

Example 11.3. Performance of Economiser and Air Pre-Heater

The actual values may be compared against design and reasons for deviation if any, needs to be

analysed.

Draft System

Thermal power plant has several fans such as Induced draft (ID) fans, Forced draft (FD) Fans, Primary

air fans (PA fans). These fans contribute to significant auxiliary power consumption.

Performance evaluation of fans

Performance evaluation of FD, PA and ID fans can be assessed as per Chapter — 4.6 (Performance

evaluation of fans and blowers).

The actual values should be compared with the design / Performance Guarantee (PG) test values and

if any deviation is found the reasons for the same has to be investigated. Based on the actual operating

parameters and diagnosis suitable energy saving measures can be implemented. The measures could

include

1.Replacement of fans

2.Impeller replacement

3.Variable speed drive application, etc

Study of air infiltration into the draft system

Air infiltration in the system has very adverse impact on the boiler loading, efficiency, power

consumption of the ID fans, plant load factor etc.

Checks for air infiltration in to the system have to be performed periodically once in a month by

monitoring oxygen content at the following sections:

1.Before and after air preheater

2.Before and after ESP

3.Before and after ID fan

The difference in the oxygen gives the extent of air filtration into the system. Measurement of oxygen

content across all the units in flue gas path, indicates the locations where infiltration is occurring.

Based on the oxygen content, coal flow and stoichiometric air requirement (in case where measurement

of air flow across all units in the flue gas path is not possible) the flue gas quantity shall be estimated.

These gas quantities should be compared with the design/PG test or best-run values for that particular

loading.

The induced draft effect is highest at ID fan inlet and the air in leakages can be pronounced in locations

like ESP hoppers APH hoppers, duct work etc which are close to ID fans. Reduction in air infiltration

will result in

1.Reduced power consumption of ID fans

2.Reduced boiler losses

3.Improvement in boiler loading

4.Increased unit load

5.Increased capacity margins in ID fan

Water Pumping System

Water pumping is a vital energy consuming area in thermal power plant and the major pumps in thermal power plant are Boiler feed water pumps, Condensate extraction pumps, cooling tower pumps, raw water pumps, ash slurry pumps etc.

Boiler feed pump is the major consumer among all power consuming equipment in the power plant.

BFP may constitute more than 20% of the total auxiliary power consumption.

For performance assessment of pumping system refer Chapter — 4.7 Energy performance assessments

of water pumps

The actual values should be compared with the design / performance guarantee values and if any deviation is found the reasons for the same has to be investigated. Based on the actual operating parameters and diagnosis suitable energy saving measures can be implemented. The measures could

include

1. Replacement of pumps

2.Impeller replacement/trimming

3.Variable speed drive application

4.Optimizing number of pumps in operation, etc

LP and HP Heaters

LP heaters and HP heaters constitute the regenerative portion of the Rankine cycle, wherein the temperature of the condensate from the hot well is boosted to, optimally higher values, upto the deaerator, in LP heaters, using steam extracted from the LP and IP turbines. From the deaerator onward, the fluid is referred to as feed water, which is pumped by the Boiler Feed Pumps (BFP’s), through the HP heaters and then through the economizer into the boiler drum (Figure 11.7). The performance of the feed water heaters can be analysed by assessing the following

Terminal Temperature Difference (TTD)

It is the difference between the saturation temperature at the operating pressure of the inlet steam to

the heater and the temperature of the feed water leaving the heater (Figure 11.7).

Drain Cooler Approach (DCA)

It is the difference between the temperature of the drains (steam condensate) leaving the heater and

temperature of the feed water entering the heater (Figure 11.7).

The lower the TTD and DCA, the more efficient the cycle. The more efficient cycle results in a

lower heat rate and reduced fuel cost.

The illustrative profile of typical heat transfer zones in heaters is presented in Figure 11.7.

In some of the cases, because of the de-superheating zone in the heater, the feed water temperature leaving the heater may be higher than the saturation temperature of the condensing zone. Therefore, the heater may have a negative TTD as shown in the figure. If the de-superheating zone of the heater is removed, the feed water outlet temperatures will be less than the saturation temperature, which results in a positive TTD. The practical lower TTD limit on a heater without a de-superheating zone is + 1.1 °C. The negative TTD limit for a heater with de-superheating zone depends on the amounts of superheat in the extraction steam entering the heater

Example 11.4. Calculation of performance parameters based on the data given in the following table.

Terminal Temperature Difference (TTD)

TTD =Saturation temp. of extraction steam,° C — Feed water outlet temp., °C

TTD =86.5 °C—77.5 °C

TTD=9 °C

Drain Cooler Approach (DCA)

DCA = Drain outlet temp.,° C — Inlet feed water temp.,° C

DCA =61.8 °C—47 °C

DCA =14.8 °C

Increased values of TTD and DCA with respect to the design values indicate extent of drop in heat

transfer mainly due to fouling.

Turbine

The steam turbines are split into three separate stages, High Pressure (HP), Intermediate Pressure (IP) and Low Pressure (LP) stage. After the steam has passed through the HP stage, it is returned to the boiler to be re-heated to its original temperature although the pressure remains greatly reduced. The reheated steam then passes through the IP stage and finally to the LP stage of the turbine.

ASME PTC-6S Steam Turbine performance test code is referred for assessing the performance of Steam Turbine.

The performance of the steam turbines can be analysed by assessing the following

1.Turbine heat rate

2.Turbine cycle efficiency (thermal efficiency)

3.Stage (isentropic) turbine efficiency

4.Specific steam consumption

Performance measurements

The temperature, pressure and flow measurements for the following are necessary

1. Feed water at Inlet & Outlet of Heaters

2. Main steam

3. HP turbine extraction

4. Hot reheat steam, Cold reheat Steam

5. IP extraction

6. JP Exhaust

In addition to the above, the generator output is to be noted

Turbine heat rate

Turbine heat rate is defined as the amount of heat input to the turbine in kcal for generating one unit of electricity.

Turbine cycle efficiency (thermal efficiency)

Turbine cycle efficiency is defined as the amount of electricity produced to the heat input to the turbine.

It is reciprocal of heat rate in consistent units.

Turbine stage (isentropic) efficiency

The efficiency method given in this procedure is the enthalpy drop efficiency method. This method determines the ratio of actual enthalpy drop across turbine section to the isentropic enthalpy drop. This method provides a good measure for monitoring purposes.

Each section of the turbine must be considered as a separate turbine. Each section should be tested and the results are trended separately. While conducting the tests, it has to be ensured that, it is conducted over normal operating load range.

After evaluating the turbine heat rate and efficiency, the deviation from the design, if any should be

assessed and the factors contributing to the deviations must be identified. The major factors to be

looked into are:

1. Main steam and reheat steam inlet parameters

2.Turbine exhaust steam parameters

3.Reheater and super heater spray

4.Passing of high energy draining

5.Loading on the turbine

6.Boiler loading and boiler performance

7.Operations and maintenance constraints

8.Condenser performance and cooling water parameters

9.Silica deposition and its impact on the turbine efficiency

10.Inter stage sealing, balance drum and gland sealing

11.Nozzle blocks

12.Turbine blade erosion

13.Functioning of the valves

14.Operational status of HP heaters

15.Performance of reheaters

Example 11.6.

A small scale biomass power plant is to be installed with the following parameters

Turbine inlet steam pressure is 66 kg/cm? (g) and temperature is 480 °C

Condensing pressure of the turbine is 0.18 kg/cm? (a)

Stage (isentropic) efficiency = 85%

Dryness factor of steam more than 88%

Boiler efficiency (thermal) = 71% on GCV of bagasse

GCV of fuel (bagasse) = 2276 kcal/kg

Maximum steam flow rate of Boiler = 80 TPH

Mechanical efficiency of turbine = 0.985

. Efficiency of generator = 0.95

10. T-G gear efficiency = 0.98

CO NAHRWN SE

Calculate the following

1. Steam generated by one tonne of bagasse

2. Quantity of bagasse required for 80 TPH of steam generation

3. Specific steam consumption of turbine

4. Power generated

Solution

Enthalpy of steam at 66 kg/cm” (g) and temperature 480 °C (H))

= 804.4 kcal/kg

Isentropic enthalpy of steam at 0.18 kg/cm? (a) (H2-is)

= 528.8 kcal/kg

Condenser

Condenser is the most important equipment of power plant cycle. It plays a vital role in determining the heat rate of Turbine. It ensures maintaining of vacuum and hence the back pressure of the Turbine at which exhaust steam from turbine condenses. Lower the condenser back pressure lower is the condensing temperature of steam and hence increase in turbine cycle efficiency. The condensate  formed is reused as feed water in Boiler through the feed water heaters and deaerator.

Due to the low condenser back pressure (high condenser vacuum), the exhaust steam from Turbine expands to a greater extent resulting in increased availability of heat energy for converting into mechanical work in Turbine and hence more Generator output. The Turbine output varies with  condenser back pressure. As the condenser back pressure increases, the Turbine output decreases because each unit mass of steam does less work on the turbine.

The exhaust part of the steam turbines is designed with specific value of condenser back pressure. As the condenser back pressure increases above design value, the steam temperature in the condenser increases resulting in reduction of power output and increase in Turbine cycle heat rate and unit heat rates. Hence it is important to monitor the performance of the condenser and ensure its design back pressure.

Purpose of the Condenser Performance Test

Condenser is designed for certain cooling water inlet temperature, thermal load and condenser back pressure. The performance of the condenser is expected to deteriorate over a period of time due to bad chemistry of cooling water maintained in it resulting in scale formation and tube fouling affecting the heat transfer badly.

Low cooling water flow through the condenser tubes raises the exhaust steam temperature and thus the

condenser back pressure. Air ingress into the condenser through leaky valves, pipe fittings and instrument tapings and improper functioning of Steam Jet Air Ejector will also contribute to increased condenser back pressure. Hence performance assessment of the condenser is periodically required to determine:

i. Condenser effectiveness

ui. Condenser heat load

iii. The terminal temperature difference (TTD)

The values achieved during performance assessment are compared with the design values or performance guaranteed values or the values recorded during first time commissioning of the plant and the reasons for deviations are analysed and actions are taken to improve the performance of the condenser to its rated value and there by maintaining the efficiency of the Turbine cycle.

Performance Terms and Definitions

The above performance terms are explained in Figure 11.8. The schematic of condenser in power Plant

cycle is shown in Figure 11.9. The effect of cooling water inlet temperature on condenser back pressure is shown in Figure 11.10. From the figure it is clear that as the cooling water inlet temperature is increasing the condenser back pressure is also increasing and at the same time the condenser terminal temperature difference (TTD) as indicated in Figure 11.11. The higher TTD indicates less heat transfer is taking place inside the condenser. Figure 11.12 shows the effect of condenser back pressure on power plant cycle efficiency. As the condenser back pressure is increasing the power plant cycle efficiency is decreasing which means increased heat rate of the cycle. The increased unit heat rate will

lead to increase in fuel consumption cost and hence increased cost of power generation. The effect of back pressure on heat rate is considerable even for small variation of 0.01 kg/cm?(a) as seen in the cases of 210 MW and 500 MW units from Table 11.7. Hence it is important to monitor the performance of the condenser and to operate the power plant at its rated heat rate value.

Table 11.7.Effect of condenser back pressure on heat rate of a typical turbine cycle

Performance Measurements

The following measurements are made at the condenser.

¢ Condenser cooling water inlet temperature

¢ Condenser cooling water outlet temperature

¢ Condenser back pressure/condenser vacuum

¢ Hot well condensate temperature

¢ Condenser cooling water flow

Factors Affecting Condenser Vacuum

The reasons for low condenser vacuum are:

¢ Reduced cooling water flow

¢ Increase in cooling water inlet temperature

¢ Fouling/scaling of condenser tubes

¢ Accumulation of gases

e Large thermal load

¢ Flooding of condenser tubes

¢ Improper functioning of Steam Jet Air Ejector

Condenser Vacuum Fault Diagnostics Chart

1. High cooling water temperature rise (Tcwo — Tewi )

Arise in cooling water temperature is either due to low cooling water flow or large thermal load

coming on the condenser. Cooling water flow being normal it represents high thermal load on the condenser.

2. High terminal temperature difference (Tsat — Tcwo)

An increase in terminal temperature difference indicates interference with heat transfer due to scaling/fouling of condenser tubes.

3.High temperature difference between Tsat — Tc

A rise in temperature difference between Tsat and condensate temperature Tc; and increase in dissolved oxygen concentration of condensate indicates air ingress into the condenser.

Example 11.7.

If the condenser back pressure is 0.1 ata, calculate the condenser vacuum. Given that the atmospheric

pressure is 752 mmHg.

Solution:

Ata 1s the abbreviation for atmospheric pressure absolute and is defined as the standard atmospheric

pressure at sea level.

1 ata = latm = 760mmHg = 1.0332kg/em?*= 1.01325bar = 101.3kPa = 10.33mH,O = 29.92 inches of Hg = 14.7psia_ (Book-1, Chapter-3)

Given data: 0.1 ata                           = 760 x 0.1                   = 76 mmHg

Atmospheric pressure                      = 752mmHg

Condenser vacuum, mmHg           = (Atmospheric pressure, mmHg - Condenser back pressure, mmHg)

                                                       = (752 - 76) = 676 mmHg.

Example 11.8.

The exhaust steam pressure of a turbine is 0.051 kg/cm2(a). Calculate the condenser vacuum in millibar. Assume atmospheric pressure as 760 mmHg.

Solution:

1.0332 kg/cm2 (a) = 760 mmHg

0.051 kg/cm2 (a) = 760 x 0.051/1.0332 = 37.51 mmHg

Condenser vacuum = 760 - 37.51 = 722.49 mmHg

722.49 mmHg = 1.01325 x 722.49/760 = 963.24 millibar

Condenser vacuum = 963.24 millibar

Example 11.9.

If the condenser back pressure of a turbine is 0.11 bar(a), what is its condenser vacuum in millibar ?

Atmospheric pressure is 755 mmHg.

Solution:

1.01325 bar (a) = 760 mmHg

0.11 bar (a) = 760 x 0.11/1.01325 = 82.5 mmHg

Condenser vacuum = 755 - 82.5 = 672.5 mmHg

Condenser vacuum = 1.01325 x 672.5/760 = 896.59 millibar

Example 11.10.

The vacuum recorded in a steam power plant is 700 mmHg. Find out the absolute pressure inside the

condenser in kg/cm2 if the atmospheric pressure is 740 mmHg.

Solution:

Absolute pressure in condenser = (Atmospheric pressure - Condenser vacuum)

Absolute pressure = 740 — 700 = 40 mmHg

760 mmHg =1.0332 kg/cm2 (a)

40 mmHg = 1.0332 x 40/760 = 0.0544 kg/cm2(a)

Condenser pressure = 0.0544 kg/cm2 (a)

Example 11.11.

The cooling water inlet temperature and outlet temperature of a condenser is 30°C and 39°C

respectively. If the condenser vacuum is 684 mmHg and the atmospheric pressure is 750 mmHg.

Calculate the condenser effectiveness and TTD.

Solution:

(i) Calculation of condenser effectiveness

Condenser vacuum = 684 mmHg

Atmospheric pressure = 750 mmHg

Condenser back pressure = (750 - 684) = 66 mmHg

We know, 760 mmHg = 1.0332 kg/cm2

66 mmHg=(1.0332 x 66)/760 = 0.089725 kg/cm2

Example 11.12.

The condenser of a 210 MW turbine is designed for the following conditions.

Turbine exhaust steam flow to condenser = 560 T/hr

Condenser back pressure = 0.1042 bar(a)

Dryness fraction of steam = 88%

Cooling water inlet temperature = 30°C

Cooling water outlet temperature = 40°C

Calculate:

(1) Heat load on condenser

(11) Cooling water flow required to condense the steam

Solution:

(i) Heat load calculation:

Heat load = Steam inlet flow x L.H. of vaporisation of steam

From steam tables at 0.1042 bar (a), L.H. of vaporisation of steam is 2391 kJ/kg

L.H. of 88% dry steam = 2391 x 0.88=2104 kJ/kg

Heat load = 560 x 1000 x 2104 = 1178240000 kJ/hr

(11) Calculation of cooling water flow Q:

Heat removed by cooling water = Q x Cp x (Tcwo - Tcwi)

1178240000 /4.18 =Qx1x (40-30)

Q= 28187.6 T/hr

Solved Example:

A captive thermal plant is delivering an output of 29 MW at the generator terminal. The generator efficiency is 96%. The steam generated in a utility boiler with an efficiency of 86% at 105 ata and 485°C is fed to the turbine. The turbine exhausts steam to condenser maintained at 0.1 ata and 45.5°C. The feed water temperature at inlet to the boiler is 105°C.

Based on the above data determine:

i. Output of the steam turbine in kW

ii. Steam flow through the turbine

iil. Turbine heat rate

iv. Unit heat rate

Solution:

Enthalpy of steam at turbine exhaust = 45.5 +0.9 (618 — 45.5)

i.e. h, = 560.75 Keal/Kg.

Generator electric output = 29000 KW

Generator input = 29000 / 0.96 = 30208.33 KW

Loss in gear box = 1100 KW

Output of steam turbine = Generator input + Gear box loss

= 30208.33 + 1100

= 31308.33 kW

1) Output of the steam turbine Say = 31308 kW

ms = Steam flow through turbine

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Chapter 10

Chapter 12