I N S T R U C T I O N
PT-80/100-130/13 LMZ.
You should know the instructions:
1. head of boiler-turbine shop-2,
2. Deputy Head of the Boiler Turbine Shop for Operation-2,
3. senior shift supervisor of station-2,
4. shift supervisor at station-2,
5. shift supervisor of the turbine department of boiler-turbine shop-2,
6. operator of the central control room of steam turbines of the VI category,
7. operator-inspector for turbine equipment of the V category;
8. Level IV turbine equipment operator.
Petropavlovsk-Kamchatsky
JSC Energy and Electrification “Kamchatskenergo”.
Branch "Kamchatka CHPP".
I CONFIRM:
Chief Engineer branch of OJSC "Kamchatskenergo" KTETs
Bolotenyuk Yu.N.
“ “ 20
I N S T R U C T I O N
Instructions for use steam turbine
PT-80/100-130/13 LMZ.
Instruction validity period:
with “____” ____________ 20
by "____"____________ 20
Petropavlovsk – Kamchatsky
1. General Provisions…………………………………………………………………… 6
1.1. Criteria for safe operation of steam turbine PT80/100-130/13………………. 7
1.2. Technical data of the turbine…………………………………………………………...….. 13
1.4. Turbine protection………………………………………………………………….……………… 18
1.5. The turbine must be emergency stopped and the vacuum broken manually…………...... 22
1.6. The turbine must be stopped immediately……………………………………...... 22
The turbine must be unloaded and stopped during the period
determined by the chief engineer of the power plant……………………………..……..… 23
1.8. Long-term operation of the turbine at rated power is allowed…………………... 23
2. Short description turbine design…………………………………..… 23
3. Turbine unit oil supply system…………………………………..…. 25
4. Generator shaft sealing system……………………………………....… 26
5. Turbine control system…………………………………………...…. 30
6. Technical data and description of the generator……………………………….... 31
7. Technical characteristics and description of the condensing unit…. 34
8. Description and technical specifications regenerative plant...... 37
Description and technical characteristics of the installation for
heating of network water………………………………………………………...… 42
10. Preparing the turbine unit for start-up………………………………………….… 44
10.1. General provisions………………………………………………………………………………………...….44
10.2. Preparing to put the oil system into operation……………………………………….46
10.3. Preparing the control system for start-up……………………………………………..…….49
10.4. Preparation and start-up of the regenerative and condensing unit……………………………49
10.5. Preparation for putting into operation the installation for heating network water……………….....54
10.6. Warming up the steam pipeline to the gas processing plant………………………………………………………………………………….....55
11. Starting the turbine unit………………………………………………………..… 55
11.1. General instructions………………………………………………………………………………….55
11.2. Starting the turbine from a cold state………………………………………………………...61
11.3. Starting the turbine from a cold state……………………………………………………………….…..64
11.4. Starting the turbine from a hot state………………………………………………………..65
11.5. Peculiarities of starting a turbine using sliding parameters of fresh steam………………….…..67
12. Turning on production steam extraction………………………………... 67
13. Disabling production steam extraction…………………………….… 69
14. Turning on the cogeneration steam extraction……………………………..…. 69
15. Shutdown of cogeneration steam extraction………………………….…... 71
16. Turbine maintenance during normal operation………………….… 72
16.1 General provisions……………………………………………………………………………….72
16.2 Maintenance of the condensing unit……………………………………………………………..74
16.3 Maintenance of a regenerative unit…………………………………………………………………….….76
16.4 Maintenance of the oil supply system……………………………………………………...87
16.5 Generator maintenance…………………………………………………………………………………79
16.6 Maintenance of installation for heating network water………………………………….……80
17. Stopping the turbine……………………………………………………………… 81
17.1 General instructions for stopping the turbine……………………………………………………….……81
17.2 Turbine shutdown as a reserve, as well as for repairs without cooling……………………..…82
17.3 Shutting down the turbine for repairs with cooling…………………………………………………………...84
18. Safety requirements…………………………………….…… 86
19. Measures to prevent and eliminate turbine accidents…… 88
19.1. General instructions…………………………………………………………………………………88
19.2. Cases of turbine emergency stop………………………………………………………...90
19.3. Actions performed by turbine technological protections……………………………91
19.4. Actions of personnel in case of emergency situation on the turbine……………………………..…….92
20. Rules for admission to equipment repair……………………………….… 107
21. Procedure for admission to turbine testing…………………………………….. 108
Applications
22.1. Turbine start-up schedule from a cold state (metal temperature
The high pressure pressure in the steam inlet zone is less than 150 ˚С)………………………………………………………..… 109
22.2. Turbine start-up schedule after 48 hours of inactivity (metal temperature
HPC in the steam inlet zone 300 ˚С)………………………………………………………………..110
22.3. Turbine start-up schedule after 24 hours of inactivity (metal temperature
HPC in the steam inlet zone 340 ˚С)………………………………………………………………………………..…111
22.4. Turbine start-up schedule after 6-8 hours of inactivity (metal temperature
HPC in the steam inlet zone 420 ˚С)………………………………………………………………………………….112
22.5. Turbine start-up schedule after idle time for 1-2 hours (metal temperature
HPC in the steam inlet zone 440 ˚С)……………………………………………………..…………113
22.6. Approximate turbine start-up schedules at nominal
fresh steam parameters……………………………………………………………………………….…114
22.7. Longitudinal section of the turbine………………………………………………………..….…115
22.8. Turbine control circuit………………………………………………………..….116
22.9. Thermal diagram turbine installations…………………………………………………………….….118
23. Additions and changes……………………………………………...…. 119
GENERAL PROVISIONS.
Steam turbine type PT-80/100-130/13 LMZ with production and 2-stage heating steam extraction, rated power 80 MW and maximum 100 MW (in a certain combination of controlled extractions) is intended for direct drive of the generator alternating current TVF-110-2E U3 with a power of 110 MW, mounted on a common foundation with a turbine.
List of abbreviations and symbols:
AZV - automatic high pressure valve;
VPU - shaft turning device;
GMN - main oil pump;
GPZ - main steam valve;
KOS - check valve with a servomotor;
KEN - condensate electric pump;
MUT - turbine control mechanism;
OM - power limiter;
HPH - high pressure heaters;
LPH - low pressure heaters;
PMN - starting oil pump;
PN - seal steam cooler;
PS - seal steam cooler with ejector;
PSG-1 - network heater of the bottom extraction;
PSG-2 - the same, upper selection;
PEN - electric nutrient pump;
HPR - high pressure rotor;
RK - control valves;
RND - low pressure rotor;
RT - turbine rotor;
HPC - high pressure cylinder;
LPC - low pressure cylinder;
RMN - backup oil pump;
AMN - emergency oil pump;
RPDS - oil pressure drop relay in the lubrication system;
Ppr is the steam pressure in the production sampling chamber;
P is the pressure in the lower heating chamber;
R - the same, upper heating extraction;
Dpo - steam consumption for production extraction;
D - total flow rate for PSG-1,2;
KAZ - automatic shutter valve;
MNUV - generator shaft seal oil pump;
NOG - generator cooling pump;
ACS - automatic control system;
EGP - electrohydraulic converter;
KIS - executive solenoid valve;
TO - heating extraction;
PO - production selection;
MO - oil cooler;
RPD - differential pressure regulator;
PSM - mobile oil separator;
ZG - hydraulic shutter;
BD - damper tank;
IM - oil injector;
RS - speed controller;
RD - pressure regulator.
1.1.1. By turbine power:
Maximum turbine power when fully switched on
regeneration and certain combinations of production and
heating extraction…………………………………………………………………...100 MW
Maximum turbine power in condensing mode with HPV-5, 6, 7 turned off ………………………………………………………………………………... 76 MW
Maximum turbine power in condensing mode with PND-2, 3, 4 turned off ……………………………………………………………………...71 MW
Maximum turbine power in condensing mode when switched off
PND-2, 3, 4 and PVD-5, 6, 7 ………………………………………………………………………………….68 MW
which are included in the operation of HPV-5,6,7………………………………………………………..10 MW
Minimum turbine power in condensing mode at
which turns on the drain pump PND-2…………………………………………….20 MW
The minimum power of the turbine unit at which it is switched on
operation of adjustable turbine extractions……………………………………………………………… 30 MW
1.1.2. Based on turbine rotor speed:
Rated turbine rotor speed………………………………………………………..3000 rpm
Rated rotation speed of the turbine rotor
device ………………………………………………………………………………………..………..3.4 rpm
Maximum deviation turbine rotor speed at
in which the turbine unit is switched off by protection…………………………………….………..…..3300 rpm
3360 rpm
Critical rotation speed of the turbogenerator rotor…………………………………….1500 rpm
Critical rotation speed of the low-pressure turbine rotor…………………….……1600 rpm
Critical rotation speed of the high-pressure turbine rotor……………………….….1800 rpm
1.1.3. According to the flow of superheated steam to the turbine:
Nominal steam flow per turbine when operating in condensing mode
with the regeneration system fully turned on (at rated power
turbine unit equal to 80 MW) …………………………………………………………………………………305 t/hour
Maximum steam flow per turbine when the system is turned on
regeneration, regulated production and heating extraction
and closed control valve No. 5 …..……………………………………………………………..415 t/hour
Maximum steam flow per turbine…………………….…………………..………………470 t/hour
mode with disabled PVD-5, 6, 7 …………………………………………………………..270 t/hour
Maximum steam flow per turbine when operating on condensing
mode with disabled LPG-2, 3, 4 ………………………………………………………...………………..260t/hour
Maximum steam flow per turbine when operating on condensing
mode with disabled PND-2, 3, 4 and PVD-5, 6, 7…………………………………………..…230t/hour
1.1.4. According to the absolute pressure of superheated steam before the CBA:
Nominal absolute pressure of superheated steam before the core…………………..……….130 kgf/cm 2
Allowable reduction in absolute pressure of superheated steam
in front of the CBA during turbine operation…….……………………………………………………125 kgf/cm 2
Permissible increase in absolute pressure of superheated steam
in front of the CBA during turbine operation.…………………………………………………………………………………135 kgf/cm 2
Maximum deviation of the absolute pressure of superheated steam before the CBA
during turbine operation and with a duration of each deviation of no more than 30 minutes……..140 kgf/cm 2
1.1.5. Based on the temperature of superheated steam before the CBA:
Nominal temperature of superheated steam before the core..……………………………..…..555 0 C
Permissible decrease in superheated steam temperature
before the CBA during turbine operation..……………………………………………………….……… 545 0 C
Permissible increase in the temperature of superheated steam before
CBA during turbine operation…………………………………………………………………………………….. 560 0 C
Maximum temperature deviation of superheated steam before the core at
turbine operation and the duration of each deviation is no more than 30
minutes………………….………………..…………………………………………………….………565 0 C
Minimum temperature deviation of superheated steam before the CBA at
in which the turbine unit is switched off by protection……………………………………………………...425 0 C
1.1.6. Based on the absolute steam pressure in the turbine control stages:
with superheated steam flow rates to the turbine up to 415 t/hour. ..……………………………………...98.8 kgf/cm 2
Maximum absolute steam pressure in the control stage of the HPC
when the turbine operates in condensing mode with PVD-5, 6, 7 turned off….……….…64 kgf/cm 2
Maximum absolute steam pressure in the control stage of the HPC
when the turbine operates in condensing mode with LPG-2, 3, 4 turned off ………….…62 kgf/cm 2
Maximum absolute steam pressure in the control stage of the HPC
when the turbine operates in condensing mode with PND-2, 3, 4 turned off
and PVD-5, 6.7……………………………………………………………..……….……… .....55 kgf /cm 2
Maximum absolute steam pressure in the refueling chamber
HPC valve (behind the 4-stage) at flow rates of superheated steam to the turbine
more than 415 t/hour…………………………………………………………………………………83 kgf/cm 2
Maximum absolute steam pressure in the control chamber
LPC steps (behind the 18th step) ……………………………..……………………………………..13.5 kgf/cm 2
1.1.7. According to the absolute steam pressure in the controlled turbine extractions:
Permissible increase in absolute steam pressure in
controlled production selection………………………………………………………16 kgf/cm 2
Permissible reduction in absolute steam pressure in
controlled production selection………………………………………………………10 kgf/cm 2
The maximum deviation of the absolute steam pressure in the controlled production selection at which they are triggered safety valves………………………………………………………………………………..19.5 kgf/cm 2
upper heating selection………………………………………………………….…..2.5 kgf/cm 2
upper heating extraction………………………………………………………..……..0.5 kgf/cm 2
Maximum deviation of absolute steam pressure in regulated
upper heating selection at which it is triggered
safety valve…………………………………………………………………………………..……3.4 kgf/cm 2
Maximum deviation of absolute steam pressure in
controlled upper heating extraction in which
the turbine unit is switched off by protection…………………………………………..…………………...3.5 kgf/cm 2
Permissible increase in absolute steam pressure in a regulated
lower heating extraction………………………………………………………….……1 kgf/cm 2
Permissible reduction in absolute steam pressure in a regulated
lower heating extraction………………………………………………………….…0.3 kgf/cm 2
Maximum permissible reduction in pressure difference between the chamber
lower heating extraction and turbine condenser………………………….… up to 0.15 kgf/cm 2
1.1.8. According to the steam flow into the controlled turbine extractions:
Nominal steam flow in regulated production
selection…………………………………………………………………………………….……185 t/hour
Maximum steam flow in a controlled production…
rated turbine power and switched off
heating extraction……………………………………………………………….………245 t/hour
Maximum steam flow in controlled production
selection at an absolute pressure in it equal to 13 kgf/cm 2,
turbine power reduced to 70 MW and switched off
heating extraction…………………………………………………………………..……300 t/hour
Nominal steam flow in adjustable top
heating extraction…………………………………………………………………………………...132 t/hour
and disabled production selection………………………………………………………150 t/hour
Maximum steam flow in adjustable top
district heating with power reduced to 76 MW
turbine and switched-off production extraction……………………………………………………….……220 t/hour
Maximum steam flow in adjustable top
heating extraction at rated turbine power
and reduced to 40 t/h steam consumption in production selection……………………………200 t/h
Maximum steam flow in PSG-2 at absolute pressure
in the upper heating extraction 1.2 kgf/cm 2 …………………………………………….…145 t/hour
Maximum steam flow in PSG-1 at absolute pressure
in the lower heating extraction 1 kgf/cm2 ………………………………………………….220 t/hour
1.1.9. Based on the steam temperature in the turbine outlets:
Nominal steam temperature in regulated production
selection after OU-1, 2 (3,4) ……………………………………………………………………………………..280 0 C
Permissible increase in steam temperature in a controlled
production selection after OU-1, 2 (3,4) ………………………………………………………………...285 0 C
Permissible reduction in steam temperature in a controlled
production selection after OU-1.2 (3.4) ……………………………………………………………….…275 0 C
1.1.10. By thermal state turbines:
Maximum rate of metal temperature rise
…..……………………………..15 0 S/min.
bypass pipes from the ABC to the control valves of the HPC
at temperatures of superheated steam below 450 degrees C.…………………………………….………25 0 C
Maximum permissible metal temperature difference
bypass pipes from the ABC to the control valves of the HPC
at a temperature of superheated steam above 450 degrees C.……………………………………………………….…….20 0 C
Maximum permissible temperature difference of the top metal
and the bottom of the HPC (LPC) in the steam inlet zone ………………….…………………………………………..50 0 C
Maximum permissible metal temperature difference in
cross-section (width) of horizontal flanges
cylinder connector without turning on the heating system
HPC flanges and studs..………………………………….…………………………………80 0 C
HPC connector with heating of flanges and studs on …………………………………..…50 0 C
in the cross section (width) of the horizontal flanges
HPC connector with heating of flanges and studs on……………………………….……-25 0 C
Maximum permissible metal temperature difference between the upper
and the lower (right and left) flanges of the HPC when the
heating of flanges and studs ………………………………………………….…………………....10 0 C
Maximum permissible positive temperature difference of metal
between the flanges and studs of the HPC when the heating is on
flanges and studs……………………………………………………………….……………………….20 0 C
Maximum permissible negative temperature difference of metal
between the flanges and studs of the HPC when the heating of the flanges and studs is turned on …………………………………………………………………………………………………………..…..- 20 0 C
Maximum permissible temperature difference of metal thickness
cylinder walls, measured in the area of the control stage of the high pressure cylinder….………………………….35 0 C
bearings and turbine thrust bearing…………………………………….……...…..90 0 C
Maximum permissible temperature of support liners
generator bearings…………………………………………………….…………..………..80 0 C
1.1.11. According to the mechanical condition of the turbine:
Maximum permissible shortening of the high pressure hose relative to the central venous pressure….……………………………….-2 mm
Maximum permissible elongation of the high pressure hose relative to the central venous pressure ….…………………………………….+3 mm
Maximum permissible shortening of the RND relative to the LPC ….…………………..………-2.5 mm
Maximum permissible elongation of the RND relative to the LPC …….……………………..…….+3 mm
Maximum permissible curvature of the turbine rotor…………….…………………………..0.2 mm
Maximum permissible maximum value curvature
turbine unit shaft when passing critical rotation speeds………………………..0.25 mm
generator side……………………………………………………….…………………..…1.2 mm
Maximum permissible axial displacement of the turbine rotor in
side of the control unit ……………………………………………………………….…………………….1.7 mm
1.1.12. According to the vibration state of the turbine unit:
Maximum permissible vibration velocity of turbine unit bearings
in all modes (except for critical rotation speeds) ……………….……………………….4.5 mm/sec
when the vibration velocity of the bearings increases by more than 4.5 mm/sec……………………………30 days
Maximum permissible operating time of the turbine unit
when the vibration velocity of the bearings increases more than 7.1 mm/sec……….………………………7 days
Emergency increase in vibration velocity of any of the rotor supports ………….…………………11.2 mm/sec
Emergency sudden simultaneous increase in vibration speed of two
supports of one rotor, or adjacent supports, or two vibration components
one support from any initial value………………………………………………...by 1 mm or more
1.1.13. By flow rate, pressure and temperature of circulating water:
Total cooling water consumption for the turbine unit………….………………………….8300 m 3 /hour
Maximum cooling water flow through the condenser….…………………………..8000 m 3 /hour
Minimum consumption cooling water through the condenser……………….…………………..2000 m 3 /hour
Maximum water flow through the built-in condenser bundle……….………………1500 m 3 /hour
Minimum water flow through the built-in condenser bundle………………………..300 m 3 /hour
Maximum temperature of cooling water at the condenser inlet……………………………………………………………………………………..33 0 C
Minimum temperature of circulating water at the inlet
capacitor in period subzero temperatures outside air……………………….8 0 C
Minimum circulating water pressure at which the AVR operates circulation pumps TsN-1,2,3,4………………………………………………………..0.4 kgf/cm 2
Maximum circulating water pressure in the pipe system
left and right halves of the capacitor…………………………………….……….……….2.5 kgf/cm 2
Maximum absolute water pressure in the pipe system
built-in capacitor beam……………………………………………………………….8 kgf/cm 2
Nominal hydraulic resistance of the condenser at
clean tubes and circulating water flow rate of 6500 m 3 /hour………………………..……...3.8 m of water. Art.
Maximum temperature difference of circulating water between
its input into the capacitor and its output ……………………………………………………………..10 0 C
1.1.14. According to the flow rate, pressure and temperature of steam and chemically desalted water into the condenser:
The maximum flow rate of chemically desalted water into the condenser is ………………..………………..100 t/hour.
Maximum steam flow into the condenser in all modes
operation………………………………………………………………….………220 t/hour.
Minimum steam flow through the low-pressure turbine turbine into the condenser
with a closed rotary diaphragm……………………………………………………….……10 t/hour.
Maximum permissible temperature of the exhaust part of the LPC ……………………….……..70 0 C
The maximum permissible temperature of chemically desalted water,
entering the condenser …………………………………………………………….………100 0 C
The absolute vapor pressure in the exhaust part of the low pressure pump at which
atmospheric diaphragm valves are activated……………………………………..……..1.2 kgf/cm 2
1.1.15. Based on absolute pressure (vacuum) in the turbine condenser:
Nominal absolute pressure in the condenser…………………………….………………0.035 kgf/cm 2
Permissible decrease in vacuum in the condenser at which the warning alarm is triggered………………. ………………………..………...-0.91 kgf/cm 2
Emergency reduction of vacuum in the condenser in which
The turbine unit is switched off by protection…………… …………………………………………………………....-0.75 kgf/cm 2
by dumping hot streams into it….…………………………………………………………….….-0.55 kgf/cm 2
Permissible vacuum in the condenser when starting the turbine before
push of the turbine shaft ……………………………………………………………………………………..……-0.75 kgf/cm 2
Permissible vacuum in the condenser when starting the turbine at the end
endurance of rotation of its rotor with a frequency of 1000 rpm …………….…………………..…….-0.95 kgf/cm 2
1.1.16. According to the pressure and temperature of a pair of turbine seals:
Minimum absolute steam pressure at turbine seals
behind the pressure regulator………………………………………………………………...……….1.1 kgf/cm 2
Maximum absolute steam pressure at turbine seals
behind the pressure regulator………………………………………………………………………………….1.2 kgf/cm 2
Minimum absolute steam pressure behind turbine seals
to the pressure maintenance regulator…….…………………………………………………….….1.3 kgf/cm 2
Maximum absolute steam pressure behind turbine seals...
to the pressure maintenance regulator………………………………………………………..….1.5 kgf/cm 2
Minimum absolute steam pressure in the second seal chambers……………………...1.03 kgf/cm 2
Maximum absolute steam pressure in the second seal chambers ……………………..1.05 kgf/cm 2
Nominal steam temperature at seals……………………………………………………….150 0 C
1.1.17. Based on oil pressure and temperature for lubrication of turbine unit bearings:
Nominal excess oil pressure in the bearing lubrication system
turbine until the oil cools.…………………………………………………………………..……..3 kgf/cm 2
Nominal excess oil pressure in the lubrication system
bearings at the level of the turbine unit shaft axis…………...……………………………………………………….1 kgf/cm 2
at the level of the turbine unit shaft axis at which it is triggered
warning alarm…………………………………………………………..………..0.8 kgf/cm 2
Overpressure oils in the bearing lubrication system
at the level of the turbine unit shaft axis at which the RPM is turned on ………………………………….0.7 kgf/cm 2
Excessive oil pressure in the bearing lubrication system
at the level of the turbine unit shaft axis at which the AMS is turned on……………………………..….0.6 kgf/cm 2
Excessive oil pressure in the bearing lubrication system is at the level
axis of the turbine unit shaft at which the VPU is switched off by protection …… ………………………..…0.3 kgf/cm 2
Emergency excess oil pressure in the bearing lubrication system
at the level of the turbine shaft axis at which the turbine unit is switched off by protection ………………………………………………………………………………………….…………..0 .3 kgf/cm 2
Nominal oil temperature for lubrication of turbine unit bearings………………………..40 0 C
Maximum permissible oil temperature for bearing lubrication
turbine unit ……………………………………………………………………………………….…45 0 C
The maximum permissible oil temperature at the outlet
turbine unit bearings………………………………………………………………......65 0 C
Emergency oil temperature at the bearing drain
turbine unit………………………………………………………………………………….………75 0 C
1.1.18. Based on oil pressure in the turbine control system:
Excessive oil pressure in the turbine control system created by the PMP…………………………………………………………………………………..…………..…18 kgf/cm 2
Excessive oil pressure in the turbine control system created by the hydraulic pump…………………………………………………………………………………………..……..20 kgf/cm 2
Excessive oil pressure in the turbine control system
At which there is a ban on closing the valve on pressure and turning off the PMP….……….17.5 kgf/cm 2
1.1.19. Based on pressure, level, flow and oil temperature in the turbogenerator shaft seal system:
Excessive oil pressure in the turbogenerator shaft seal system at which the backup alternating current MNUV is switched on by the ATS……………………………………………………………8 kgf/cm 2
Excessive oil pressure in the turbogenerator shaft seal system at which the ATS is activated
backup MNUV direct current………………………………………………………………..7 kgf/cm 2
Permissible minimum difference between the oil pressure at the shaft seals and the hydrogen pressure in the turbogenerator housing…………………………..0.4 kgf/cm 2
Permissible maximum difference between the oil pressure at the shaft seals and the hydrogen pressure in the turbogenerator housing……………………….….....0.8 kgf/cm 2
Maximum difference between oil inlet pressure and pressure
oil at the output of the MFG at which it is necessary to switch to the backup oil filter of the generator……………………………………………………………………………………………….1 kgf/cm 2
Nominal oil temperature at the outlet from MOG…………………………………………………………..40 0 C
Permissible increase in oil temperature at the outlet from MOG……………………….…….…….45 0 C
1.1.20. By temperature and flow feed water through the turbine PVD group:
Nominal temperature of feed water at the inlet to the HPH group ….……………………….164 0 C
Maximum temperature of feed water at the outlet of the HPH group at the rated power of the turbine unit…………………………………………………………..…249 0 C
Maximum feed water flow through the HPH pipe system …………………...…...550 t/hour
1.2.Technical data of the turbine.
| Turbine rated power | 80 MW |
| Maximum turbine power with fully enabled regeneration for certain combinations of production and heating extraction, determined by the mode diagram | 100 MW |
| Absolute fresh steam pressure automatic shut-off valve | 130 kgf/cm² |
| Steam temperature before stop valve | 555 °C |
| Absolute condenser pressure | 0.035 kgf/cm² |
| Maximum steam flow through the turbine when operating with all extractions and any combination thereof | 470 t/h |
| Maximum steam passage into the condenser | 220 t/h |
| Cooling water flow into the condenser at a design temperature at the condenser inlet of 20 °C | 8000 m³/h |
| Absolute steam pressure of controlled production extraction | 13±3 kgf/cm² |
| Absolute steam pressure of adjustable upper heating extraction | 0.5 – 2.5 kgf/cm² |
| Absolute steam pressure of controlled lower heating extraction at single-stage scheme heating of network water | 0.3 – 1 kgf/cm² |
| Feed water temperature after HPH | 249 °C |
| Specific steam consumption (guaranteed by LMZ) | 5.6 kg/kWh |
Note: Starting a turbine unit stopped due to an increase (change) in vibration is permitted only after a detailed analysis of the causes of vibration and with permission from the chief engineer of the power plant, made in his own hand in the operational journal of the station shift supervisor.
1.6 The turbine must be stopped immediately in the following cases:
· Increasing the rotation speed above 3360 rpm.
· Detection of a rupture or through crack in non-switchable sections of oil pipelines, steam-water path, and steam distribution units.
· The appearance of hydraulic shocks in the fresh steam lines or in the turbine.
· Emergency reduction of vacuum to -0.75 kgf/cm² or activation of atmospheric valves.
A sharp decrease in the temperature of fresh food
Russian FederationRD
Standard characteristics of turbine condensers T-50-130 TMZ, PT-60-130/13 and PT-80/100-130/13 LMZ
When compiling the “Regulatory Characteristics”, the following basic designations were adopted:
Steam consumption to the condenser (steam load of the condenser), t/h;
Standard steam pressure in the condenser, kgf/cm*;
Actual steam pressure in the condenser, kgf/cm;
Cooling water temperature at the condenser inlet, °C;
Cooling water temperature at the condenser outlet, °C;
Saturation temperature corresponding to the steam pressure in the condenser, °C;
Hydraulic resistance of the condenser (pressure drop of cooling water in the condenser), mm water column;
Standard temperature pressure of the condenser, °C;
Actual temperature difference of the condenser, °C;
Heating of cooling water in the condenser, °C;
Nominal design flow rate of cooling water into the condenser, m/h;
Cooling water flow into the condenser, m/h;
Total condenser cooling surface, m;
Cooling surface of the condenser with the built-in condenser bank disconnected by water, m.
Regulatory characteristics include the following main dependencies:
1) temperature difference of the condenser (°C) from the steam flow into the condenser (steam load of the condenser) and the initial temperature of the cooling water at the nominal flow of cooling water:
2) steam pressure in the condenser (kgf/cm) from the steam flow into the condenser and the initial temperature of the cooling water at the nominal cooling water flow:
3) temperature difference of the condenser (°C) from the steam flow into the condenser and the initial temperature of the cooling water at a cooling water flow rate of 0.6-0.7 nominal:
4) steam pressure in the condenser (kgf/cm) from the steam flow into the condenser and the initial temperature of the cooling water at a cooling water flow rate of 0.6-0.7 - nominal:
5) temperature difference of the condenser (°C) from the steam flow into the condenser and the initial temperature of the cooling water at a cooling water flow rate of 0.44-0.5 nominal;
6) steam pressure in the condenser (kgf/cm) from the steam flow into the condenser and the initial temperature of the cooling water at a cooling water flow rate of 0.44-0.5 nominal:
7) hydraulic resistance of the condenser (pressure drop of cooling water in the condenser) from the flow rate of cooling water with an operationally clean cooling surface of the condenser;
8) corrections to turbine power for deviation of exhaust steam pressure.
Turbines T-50-130 TMZ and PT-80/100-130/13 LMZ are equipped with condensers, in which about 15% of the cooling surface can be used to heat make-up or return network water (built-in bundles). It is possible to cool the built-in bundles with circulating water. Therefore, in the “Regulatory Characteristics” for turbines of the T-50-130 TMZ and PT-80/100-130/13 LMZ types, the dependences according to paragraphs 1-6 are also given for condensers with disconnected built-in bundles (with a cooling surface reduced by approximately 15% condensers) at cooling water flow rates of 0.6-0.7 and 0.44-0.5.
For the PT-80/100-130/13 LMZ turbine, the characteristics of the condenser with the built-in beam turned off at a cooling water flow rate of 0.78 nominal are also given.
3. OPERATIONAL CONTROL OF THE OPERATION OF THE CONDENSING UNIT AND THE CONDITION OF THE CONDENSER
The main criteria for assessing the operation of a condensing unit, characterizing the condition of the equipment at a given steam load of the condenser, are the steam pressure in the condenser and the temperature pressure of the condenser that meets these conditions.
Operational control over the operation of the condensing unit and the condition of the condenser is carried out by comparing the actual steam pressure in the condenser measured under operating conditions with the standard steam pressure in the condenser determined for the same conditions (the same steam load of the condenser, flow rate and temperature of the cooling water), as well as by comparing the actual temperature condenser pressure with standard.
A comparative analysis of measurement data and standard performance indicators of the installation makes it possible to detect changes in the operation of the condensing unit and establish their probable causes.
A feature of turbines with controlled steam extraction is their long-term operation, with low steam flows into the condenser. In the mode with heating extraction, monitoring the temperature pressure in the condenser does not give a reliable answer about the degree of contamination of the condenser. Therefore, it is advisable to monitor the operation of the condensing unit when the steam flow into the condenser is at least 50% and when condensate recirculation is turned off; this will increase the accuracy of determining the steam pressure and temperature difference of the condenser.
In addition to these basic quantities, for operational monitoring and analysis of the operation of a condensing unit, it is also necessary to reliably determine a number of other parameters on which the exhaust steam pressure and temperature pressure depend, namely: the temperature of incoming and outgoing water, the steam load of the condenser, the flow rate of cooling water and etc.
The influence of air suction in air removal devices operating within the operating characteristics is insignificant, while the deterioration of air density and an increase in air suction exceeding the operating capacity of the ejectors have a significant impact on the operation of the condensing unit.
Therefore, air density control vacuum system turbine units and maintaining air suction at the level of PTE standards is one of the main tasks during operation condensing units.
The proposed Standard characteristics are based on air suction values that do not exceed PTE standards.
Below are the main parameters that need to be measured during operational monitoring of the condition of the capacitor, and some recommendations for organizing measurements and methods for determining the main controlled quantities.
3.1. Exhaust steam pressure
To obtain representative data on the condenser exhaust steam pressure under operating conditions, measurements must be made at the points specified in the Standard Specifications for each condenser type.
Exhaust steam pressure must be measured by liquid mercury instruments with an accuracy of at least 1 mmHg. (single-glass cup vacuum gauges, barovacuum tubes).
When determining the pressure in the condenser, it is necessary to introduce appropriate corrections to the instrument readings: for the temperature of the mercury column, for the scale, for capillarity (for single-glass instruments).
The pressure in the condenser (kgf/cm) when measuring vacuum is determined by the formula
Where is barometric pressure (as adjusted), mm Hg;
Vacuum determined by vacuum gauge (with corrections), mm Hg.
The pressure in the condenser (kgf/cm) when measured with a barovacuum tube is determined as
Where is the pressure in the condenser, determined by the device, mm Hg.
Barometric pressure must be measured with a mercury inspector's barometer with the introduction of all corrections required according to the instrument's passport. It is also possible to use data from the nearest weather station, taking into account the difference in heights of the objects.
When measuring exhaust steam pressure, the laying of impulse lines and installation of instruments must be carried out in compliance with the following rules for installing instruments under vacuum:
- the internal diameter of the impulse tubes must be at least 10-12 mm;
- impulse lines must have a total slope towards the capacitor of at least 1:10;
- the tightness of the impulse lines must be checked by pressure testing with water;
- It is prohibited to use locking devices with seals and threaded connections;
- measuring devices must be connected to impulse lines using thick-walled vacuum rubber.
3.2. Temperature difference
Temperature difference (°C) is defined as the difference between the saturation temperature of the exhaust steam and the temperature of the cooling water at the condenser outlet
In this case, the saturation temperature is determined from the measured pressure of the exhaust steam in the condenser.
Monitoring the operation of condensing units of heating turbines should be carried out in the condensing mode of the turbine with the pressure regulator turned off in the production and heating extractions.
The steam load (steam flow into the condenser) is determined by the pressure in the chamber of one of the extractions, the value of which is the control.
The steam flow (t/h) into the condenser in condensing mode is equal to:
Where is the consumption coefficient, numeric value which is given in the technical data of the condenser for each type of turbine;
Steam pressure in the control stage (sampling chamber), kgf/cm.
If it is necessary to monitor the operation of the condenser in the heating mode of the turbine, the steam flow is determined approximately by calculation based on the steam flow to one of the intermediate stages of the turbine and the steam flow to the heating extraction and low-pressure regenerative heaters.
For the T-50-130 TMZ turbine, the steam flow (t/h) into the condenser in heating mode is:
- with single-stage heating of network water
- with two-stage heating of network water
Where and are the steam consumption, respectively, through the 23rd (for single-stage) and 21st (for two-stage heating of network water) stages, t/h;
Consumption of network water, m/h;
; - heating of network water in horizontal and vertical network heaters, respectively, °C; is defined as the temperature difference between the network water after and before the corresponding heater.
The steam flow through the 23rd stage is determined according to Fig. I-15, b, depending on the fresh steam flow to the turbine and the steam pressure in the lower heating extraction.
The steam flow through the 21st stage is determined according to Fig. I-15, a, depending on the fresh steam flow to the turbine and the steam pressure in the upper heating extraction.
For PT turbines, the steam flow (t/h) into the condenser in heating mode is:
- for turbines PT-60-130/13 LMZ
- for turbines PT-80/100-130/13 LMZ
Where is the steam consumption at the outlet of the CSD, t/h. Determined according to Fig. II-9 depending on the steam pressure in the heating extraction and in the V extraction (for PT-60-130/13 turbines) and according to Fig. III-17 depending on the steam pressure in the heating extraction and in the IV extraction ( for turbines PT-80/100-130/13);
Water heating in network heaters, °C. Determined by the temperature difference between the network water after and before the heaters.
The pressure accepted as the control pressure must be measured with spring instruments of accuracy class 0.6, periodically and carefully checked. To determine the true value of pressure in the control stages, it is necessary to introduce appropriate corrections to the instrument readings (for the installation height of the instruments, correction according to the passport, etc.).
The flow rates of fresh steam to the turbine and network water, necessary to determine the steam flow rate to the condenser, are measured by standard flow meters with corrections for deviations of the operating parameters of the medium from the calculated ones.
The temperature of the network water is measured by mercury laboratory thermometers with a division value of 0.1 °C.
3.4. Cooling water temperature
The cooling water temperature entering the condenser is measured at one point on each penstock. The water temperature at the outlet of the condenser must be measured at at least three points in one cross section of each drain conduit at a distance of 5-6 m from the outlet flange of the condenser and determined as the average based on thermometer readings at all points.
The temperature of the cooling water must be measured by mercury laboratory thermometers with a division value of 0.1 °C, installed in thermometric sleeves with a length of at least 300 mm.
3.5. Hydraulic resistance
Control of contamination of tube sheets and condenser tubes is carried out by the hydraulic resistance of the condenser through the cooling water, for which the pressure difference between the pressure and drain pipes of the condensers is measured using a mercury double-glass U-shaped differential pressure gauge installed at a level below the pressure measurement points. Impulse lines from pressure and drain pipes capacitors must be filled with water.
The hydraulic resistance (mm water column) of the condenser is determined by the formula
Where is the difference measured by the device (adjusted for the temperature of the mercury column), mm Hg.
When measuring the hydraulic resistance, the flow of cooling water into the condenser is also determined to allow comparison with the hydraulic resistance according to the Standard characteristics.
3.6. Cooling water flow
The cooling water flow to the condenser is determined by heat balance capacitor or direct measurement with segment diaphragms installed on pressure supply water lines. Cooling water flow (m/h) based on the thermal balance of the condenser is determined by the formula
Where is the difference in heat content of exhaust steam and condensate, kcal/kg;
Heat capacity of cooling water, kcal/kg·°С, equal to 1;
Density of water, kg/m, equal to 1.
When drawing up the Standard Characteristics, it was taken to be 535 or 550 kcal/kg, depending on the operating mode of the turbine.
3.7. Air density of vacuum system
The air density of the vacuum system is controlled by the amount of air at the exhaust of the steam jet ejector.
4. ASSESSMENT OF THE REDUCTION IN THE POWER OF A TURBINE UNIT DURING OPERATION WITH A REDUCED COMPARED TO THE STANDARD VACUUM
The deviation of the pressure in the condenser of a steam turbine from the standard one leads, for a given heat consumption to the turbine unit, to a decrease in the power developed by the turbine.
The change in power when the absolute pressure in the turbine condenser differs from its standard value is determined from experimentally obtained correction curves. The correction graphs included in the Standard Capacitor Characteristics data show the change in power for various values of steam flow in the turbine low-pressure pump. For a given mode of the turbine unit, the value of the change in power when the pressure in the condenser changes from to is determined from the corresponding curve.
This value of the change in power serves as the basis for determining the excess of the specific heat consumption or specific fuel consumption established at a given load for the turbine.
For turbines T-50-130 TMZ, PT-60-130/13 and PT-80/100-130/13 LMZ, the steam flow rate in the ChND for determining the underproduction of turbine power due to an increase in pressure in the condenser can be taken equal to the steam flow rate in capacitor.
I. NORMATIVE CHARACTERISTICS OF CONDENSER K2-3000-2 TURBINES T-50-130 TMZ
1. Capacitor technical data
Cooling surface area:
without built-in beam | |
Tube diameter: | |
outer | |
interior | |
Number of tubes | |
Number of water strokes | |
Number of threads | |
Air removal device - two steam jet ejectors EP-3-2 |
- in condensation mode - according to the steam pressure in the IV selection:
2.3. The difference in heat content of exhaust steam and condensate () is taken as follows:
Figure I-1. Dependence of temperature pressure on steam flow into the condenser and cooling water temperature:
7000 m/h; =3000 m
Figure I-2. Dependence of temperature pressure on steam flow into the condenser and cooling water temperature:
5000 m/h; =3000 m
Figure I-3. Dependence of temperature pressure on steam flow into the condenser and cooling water temperature:
3500 m/h; =3000 m
Figure I-4. Dependence of absolute pressure on steam flow into the condenser and cooling water temperature:
7000 m/h; =3000 m
Figure I-5. Dependence of absolute pressure on steam flow into the condenser and cooling water temperature:
5000 m/h; =3000 m
Figure I-6. Dependence of absolute pressure on steam flow into the condenser and cooling water temperature:
3500 m/h; =3000 m
Figure I-7. Dependence of temperature pressure on steam flow into the condenser and cooling water temperature:
7000 m/h; =2555 m
Figure I-8. Dependence of temperature pressure on steam flow into the condenser and cooling water temperature:
5000 m/h; =2555 m
Figure I-9. Dependence of temperature pressure on steam flow into the condenser and cooling water temperature:
3500 m/h; =2555 m
Figure I-10. Dependence of absolute pressure on steam flow into the condenser and cooling water temperature:
7000 m/h; =2555 m
Figure I-11. Dependence of absolute pressure on steam flow into the condenser and cooling water temperature:
5000 m/h; =2555 m
Figure I-12. Dependence of absolute pressure on steam flow into the condenser and cooling water temperature:
3500 m/h; =2555 m
Figure I-13. Dependence of hydraulic resistance on the flow of cooling water into the condenser:
1 - full surface capacitor; 2 - with the built-in beam disabled
Figure I-14. Correction to the power of the T-50-130 TMZ turbine for deviation of the steam pressure in the condenser (according to the “Typical energy characteristics of the T-50-130 TMZ turbine unit.” M.: SPO Soyuztekhenergo, 1979)
Fig. l-15. Dependence of steam flow through the T-50-130 TMZ turbine on fresh steam flow and pressure in the upper heating selection (with two-stage heating of network water) and pressure in the lower heating selection (with single-stage heating of network water):
a - steam flow through the 21st stage; b - steam flow through the 23rd stage
II. NORMATIVE CHARACTERISTICS OF CONDENSER 60KTSS TURBINE PT-60-130/13 LMZ
1. Technical data
Total cooling surface area | |
Nominal steam flow to the condenser | |
Estimated amount of cooling water | |
Active length of condenser tubes Tube diameter: | |
outer | |
interior | |
Number of tubes | |
Number of water strokes | |
Number of threads |
Air removal device - two steam jet ejectors EP-3-700
2. Instructions for determining some parameters of the condensing unit
2.1. The exhaust steam pressure in the condenser is determined as the average value of two measurements.
The location of the vapor pressure measurement points in the condenser neck is shown in the diagram. The pressure measurement points are located in a horizontal plane passing 1 m above the plane of connection of the condenser with the adapter pipe.
2.2. Determine the steam flow into the condenser:
- in condensation mode - by steam pressure in the V selection;
- in heating mode - in accordance with the instructions in Section 3.
2.3. The difference in heat content of exhaust steam and condensate () is taken as follows:
- for condensation mode 535 kcal/kg;
- for heating mode 550 kcal/kg.
Fig.II-1. Dependence of temperature pressure on steam flow into the condenser and cooling water temperature:
Fig.II-2. Dependence of temperature pressure on steam flow into the condenser and cooling water temperature:
Fig.II-3. Dependence of temperature pressure on steam flow into the condenser and cooling water temperature:
Fig.II-4. Dependence of absolute pressure on steam flow into the condenser and cooling water temperature:
Fig.II-5. Dependence of absolute pressure on steam flow into the condenser and cooling water temperature:
Fig.II-6. Dependence of absolute pressure on steam flow into the condenser and cooling water temperature.
The heating steam turbine PT-80/100-130/13 with industrial and heating steam extraction is designed to directly drive the TVF-120-2 electric generator with a rotation speed of 50 rps and release heat for production and heating needs.
The nominal values of the main parameters of the turbine are given below.
Power, MW
nominal 80
maximum 100
Steam ratings
pressure, MPa 12.8
temperature, 0 C 555
Consumption of extracted steam for production needs, t/h
nominal 185
maximum 300
Limits for changes in steam pressure in a controlled heating outlet, MPa
upper 0.049-0.245
lower 0.029-0.098
Production selection pressure 1.28
Water temperature, 0 C
nutritious 249
cooling 20
Cooling water consumption, t/h 8000
The turbine has the following adjustable steam extractions:
production with absolute pressure (1.275 0.29) MPa and two heating extractions - upper with absolute pressure in the range of 0.049-0.245 MPa and lower with pressure in the range of 0.029-0.098 MPa. The heating bleed pressure is regulated using one control diaphragm installed in the upper heating bleed chamber. The regulated pressure in the heating outlets is maintained: in the upper outlet - when both heating outlets are turned on, in the lower outlet - when one lower heating outlet is on. Network water must be passed through the network heaters of the lower and upper heating stages sequentially and in equal quantities. The flow of water passing through network heaters must be controlled.
The turbine is a single-shaft two-cylinder unit. The flow part of the HPC has a single-coil control stage and 16 pressure levels.
The flow part of the LPC consists of three parts:
the first (up to the upper heating outlet) has a control stage and 7 pressure levels,
second (between heating extractions) two pressure stages,
the third - a regulating stage and two pressure stages.
High pressure rotor is solid forged. The first ten disks of the low-pressure rotor are forged integrally with the shaft, the remaining three disks are mounted.
The turbine steam distribution is nozzle. At the exit from the HPC, part of the steam goes to the controlled production extraction, the rest is sent to the LPC. Heating extractions are carried out from the corresponding LPC chambers.
To reduce warm-up time and improve start-up conditions, steam heating of flanges and studs and live steam supply to the front seal of the HPC are provided.
The turbine is equipped with a shaft turning device that rotates the shaft line of the turbine unit at a frequency of 3.4 rpm.
The turbine blade apparatus is designed to operate at a network frequency of 50 Hz, which corresponds to a turbine unit rotor speed of 50 rpm (3000 rpm). Long-term operation of the turbine is allowed with a network frequency deviation of 49.0-50.5 Hz.
STEAM TURBINE PLANT PT-80/100-130/13
80 MW POWER
Steam condensing turbine PT-80/100-130/13 (Fig. 1) with controlled steam extraction (production and two-stage heating) with a nominal power of 80 MW, with a rotation speed of 3000 rpm, is intended for direct drive of an alternating current generator with a power of 120 MW type TVF-120-2 when working in a block with a boiler unit.
The turbine has a regenerative device for heating feed water, network heaters for stepwise heating of network water and must work in conjunction with a condensing unit (Fig. 2).
The turbine is designed to operate with the following basic parameters, which are presented in Table 1.
The turbine has adjustable steam extraction: production with a pressure of 13±3 kgf/cm 2 abs.; two district heating extractions (for heating network water): upper with a pressure of 0.5-2.5 kgf/cm 2 abs.; lower - 0.3-1 kgf/cm 2 abs.
Pressure regulation is carried out using one control diaphragm installed in the lower heating chamber.
The regulated pressure in the district heating extractions is maintained: in the upper extraction when two heating extractions are switched on, in the lower – when one lower heating extraction is switched on.
Heating of feed water is carried out sequentially in the HDPE, deaerator and HPH, which are fed with steam from turbine extractions (regulated and unregulated).
Data on regenerative selections are given in table. 2 and correspond to the parameters in all respects.
Table 1 Table 2
|
Heater |
Steam parameters in the sampling chamber |
Quantity selected steam, t/h |
|
|
Pressure, kgf/cm 2 abs. |
Temperature, С |
||
|
PVD No. 6 |
|||
|
Deaerator |
|||
|
HDPE No. 2 |
|||
|
HDPE No. 1 |
|||
The feed water entering the regenerative system of the turbine unit from the deaerator has a temperature of 158° C.
At nominal parameters of fresh steam, cooling water flow rate of 8000 m3 h, cooling water temperature of 20 ° C, regeneration fully turned on, the amount of water heated in the HPH equal to 100% steam flow rate, when the turbine unit is operating according to the scheme with a deaerator 6 kgf/ cm 2 abs. with stepwise heating of network water, with full use of the turbine throughput and minimal steam passage into the condenser, the following values of regulated extractions can be taken: nominal values of regulated extractions at a power of 80 MW; production selection 185 t/h at a pressure of 13 kgf/cm 2 abs.; total heating extraction 132 t/h at pressures: in the upper extraction 1 kgf/cm 2 abs. and in the lower selection 0.35 kgf/cm 2 abs.; the maximum value of production extraction at a pressure in the extraction chamber of 13 kgf/cm 2 abs. is 300 t/h; with this value of production extraction and the absence of heating extraction, the turbine power will be 70 MW; with a nominal power of 80 MW and the absence of heating extraction, the maximum production extraction will be about 245 t/h; the maximum total value of district heating extraction is 200 t/h; with this amount of withdrawal and the absence of production withdrawal, the capacity will be about 76 MW; with a rated power of 80 MW and no production extraction, the maximum heating extraction will be 150 t/h. In addition, a rated power of 80 MW can be achieved with a maximum heating output of 200 t/h and a production output of 40 t/h.
Long-term operation of the turbine is allowed with the following deviations of the main parameters from the nominal ones: fresh steam pressure 125-135 kgf/cm 2 abs.; fresh steam temperature 545-560° C; increasing the temperature of the cooling water at the condenser inlet to 33 ° C and the cooling water flow rate of 8000 m 3 h; simultaneous reduction in the amount of production and heating steam extraction to zero.
When the fresh steam pressure increases to 140 kgf/cm 2 abs. and temperatures up to 565° C, turbine operation is allowed for no more than 30 minutes, and the total duration of turbine operation at these parameters should not exceed 200 hours per year.
Long-term operation of a turbine with a maximum power of 100 MW with certain combinations of production and heating extractions depends on the magnitude of extractions and is determined by the regime diagram.
Turbine operation is not allowed: when the steam pressure in the production sampling chamber is above 16 kgf/cm 2 abs. and in the heating extraction chamber above 2.5 kgf/cm 2 abs.; when the steam pressure in the overload valve chamber (behind the 4th stage) is above 83 kgf/cm 2 abs.; when the steam pressure in the chamber of the LPC control wheel (behind the 18th stage) is above 13.5 kgf/cm 2 abs.; when the pressure regulators are turned on and the pressure in the production sampling chamber is below 10 kgf/cm 2 abs., and in the lower heating sampling chamber below 0.3 kgf/cm 2 abs.; for exhaust into the atmosphere; turbine exhaust temperature above 70° C; according to a temporary unfinished installation scheme; with the upper heating extraction switched on and the lower heating extraction switched off.
The turbine is equipped with a shaft turning device that rotates the turbine rotor.
The turbine blade unit is designed to operate at a network frequency of 50 Hz (3000 rpm).
Long-term operation of the turbine is allowed with deviations in the network frequency within the range of 49-50.5 Hz, short-term operation at a minimum frequency of 48.5 Hz, and startup of the turbine on sliding steam parameters from cold and hot states.
The approximate duration of turbine starts from various thermal states (from shock to rated load): from a cold state - 5 hours; after 48 hours of inactivity - 3 hours 40 minutes; after 24 hours of inactivity - 2 hours 30 minutes; after 6-8 hours of inactivity - 1 hour 15 minutes.
It is allowed to operate the turbine at idle speed after load shedding for no more than 15 minutes, provided that the condenser is cooled with circulating water and the rotary diaphragm is fully open.
Guaranteed heat costs. In table Table 3 shows the guaranteed specific heat consumption. Specific steam consumption is guaranteed with a tolerance of 1% over the test accuracy tolerance.
Table 3
|
Power at generator terminals, MW |
Production selection |
Heat extraction |
Temperature of network water at the inlet to the network heater, PSG 1, °C |
Generator efficiency, % |
Feedwater heating temperature, °C |
Specific heat consumption, kcal/kWh |
||
|
Pressure, kgf/cm 2 abs. |
Pressure, kgf/cm 2 abs. |
Amount of steam taken, t/h |
||||||
* Pressure regulators in the selections are turned off.
Turbine design. The turbine is a single-shaft two-cylinder unit. The flow part of the HPC has a single-coil control stage and 16 pressure levels.
The flow part of the LPC consists of three parts: the first (up to the upper heating extraction) has a control stage and seven pressure levels, the second (between the heating extractions) has two pressure levels and the third has a control stage and two pressure levels.
The high pressure rotor is solid forged. The first ten disks of the low-pressure rotor are forged integrally with the shaft, the remaining three disks are mounted.
The HPC and LPC rotors are rigidly connected to each other using flanges forged integrally with the rotors.
The rotors of the LPC and the TVF-120-2 type generator are connected by means of a rigid coupling.
Critical speeds of turbine and generator shafting per minute: 1,580; 2214; 2470; 4650 correspond to I, II, III and IV tones of transverse vibrations.
The turbine has nozzle steam distribution. Fresh steam is supplied to a free-standing steam box in which an automatic shutter is located, from where the steam flows through bypass pipes to the turbine control valves.
Upon exiting the HPC, part of the steam goes to the controlled production extraction, the rest is sent to the LPC.
Heat extraction is carried out from the corresponding LPC chambers. Upon exiting the last stages of the low pressure turbine turbine, the exhaust steam enters a surface-type condenser.
The turbine is equipped with steam labyrinth seals. Steam is supplied to the penultimate compartments of the seals at a pressure of 1.03-1.05 kgf/cm 2 abs. a temperature of about 140°C from a collector fed by steam from the equalizing line of the deaerator (6 kgf/cm 2 abs.) or the steam space of the tank.
From the outermost compartments of the seals, the steam-air mixture is sucked by an ejector into a vacuum cooler.
The turbine fixing point is located on the turbine frame on the generator side, and the unit expands towards the front bearing.
To reduce warm-up time and improve start-up conditions, steam heating of flanges and studs and live steam supply to the front seal of the HPC are provided. Regulation and protection.
1- power limiter; 2-block of speed regulator spools; 3-remote control; 4-automatic shutter servomotor; 5-speed regulator; 6-safety regulator; 7-spool safety regulator; 8-remote servomotor position indicator; 9-CVD servomotor; 10-servomotor ChSD; 11-servomotor ChND; 12-electrohydraulic converter (EGC); 13-summing spools; 14-emergency electric pump; 15-reserve electric lubrication pump; 16-start electric pump of the control system (AC);
I-pressure line 20 kgf/cm 2 abs.;II-line to the spool of the HPC servomotor;III-line to the spool of the servomotor Ch"SD; IV-line to the spoolat the servomotor ChND; V-suction line of centrifugal main pump; VI-lubrication line to oil coolers; VII-line to automatic shutter; VIII-line from the summing spools to the speed controller; IX line of additional protection; X - other lines.
The working fluid in the system is mineral oil.
Rearrangement of the control valves for the fresh steam inlet, the control valves in front of the CSD and the rotary diaphragm of the steam bypass in the CSD is carried out by servomotors, which are controlled by the speed regulator and the extraction pressure regulators.
The regulator is designed to maintain the rotation speed of the turbogenerator with unevenness of about 4%. It is equipped with a control mechanism that is used to: charge the safety regulator spools and open the automatic fresh steam shutter; changes in the rotation speed of the turbogenerator, and it is possible to synchronize the generator at any emergency frequency in the system; maintaining a given generator load during parallel operation of the generator; maintaining normal frequency when the generator operates alone; increasing the rotation speed when testing the safety regulator strikers.
The control mechanism can be actuated either manually, directly at the turbine, or remotely, from the control panel.
Pressure regulators of a bellows design are designed to automatically maintain steam pressure in controlled extraction chambers with unevenness of about 2 kgf/cm 2 for production extraction and about 0.4 kgf/cm 2 for district heating extraction.
The control system contains an electrohydraulic converter (EGC), the closing and opening of the control valves of which is affected by technological protection and emergency automation of the power system.
To protect against an unacceptable increase in rotation speed, the turbine is equipped with a safety regulator, two centrifugal strikers of which are instantly activated when the rotation speed reaches 11-13% above the nominal, which causes the closure of the automatic fresh steam shutter, control valves and rotary diaphragm. In addition, there is additional protection on the speed control spool block, which is triggered when the frequency increases by 11.5%.
The turbine is equipped with an electromagnetic switch, which, when triggered, closes the automatic shutter, control valves and rotary diaphragm.
The influence on the electromagnetic switch is carried out by: an axial shift relay when the rotor moves in the axial direction by an amount
exceeding the maximum permissible; vacuum relay in case of an unacceptable drop in vacuum in the condenser to 470 mm Hg. Art. (when the vacuum decreases to 650 mm Hg, the vacuum relay gives a warning signal); fresh steam temperature potentiometers in case of an unacceptable decrease in fresh steam temperature without time delay; key for remote shutdown of the turbine on the control panel; pressure drop switch in the lubrication system with a time delay of 3 s with simultaneous signaling of an alarm signal.
The turbine is equipped with a power limiter, used in special cases to limit the opening of control valves.
Check valves are designed to prevent turbine acceleration reverse flow steam and installed on pipelines (regulated and unregulated) for steam extraction. The valves are closed by a counterflow of steam and by automation.
The turbine unit is equipped with electronic regulators with actuators to maintain: set pressure steam in the end seal manifold by influencing the steam supply valve from the equalizing line of the deaerators 6 kgf/cm 2 or from the steam space of the tank; level in the condensate collector of the condenser with a maximum deviation from the set one ±200 mm (the same regulator turns on condensate recirculation at low steam flows in the condenser); level of heating steam condensate in all heaters of the regeneration system, except for HDPE No. 1.
The turbine unit is equipped protective devices: for joint shutdown of all HPHs with simultaneous switching on of the bypass line and giving a signal (the device is triggered in the event of an emergency increase in the level of condensate due to damage or violations of the density of the pipe system in one of the HPHs to the first limit); atmospheric diaphragm valves, which are installed on the exhaust pipes of the LPC and open when the pressure in the pipes increases to 1.2 kgf/cm 2 abs.
Lubrication system designed to supply oil T-22 GOST 32-74 control systems and bearing lubrication systems.
Oil is supplied to the lubrication system up to the oil coolers using two injectors connected in series.
To service the turbogenerator during its start-up, a starting oil pump with a rotation speed of 1,500 rpm is provided.
The turbine is equipped with one backup pump with an AC electric motor and one emergency pump with a DC electric motor.
When the lubricant pressure drops to the appropriate values, the backup and emergency pumps are automatically turned on by the lubricant pressure switch (RPS). The RDS is periodically tested during turbine operation.
When the pressure is below the permissible value, the turbine and shaft turning device are disconnected from the RDS signal to the electromagnetic switch.
The working capacity of the welded structure tank is 14 m 3 .
To clean the oil from mechanical impurities, filters are installed in the tank. The design of the tank allows for quick and safe filter changes. There is a fine oil filter to remove mechanical impurities, which ensures constant filtration of part of the oil flow consumed by the control and lubrication systems.
To cool the oil, two oil coolers (surface vertical) are provided, designed to operate on fresh cooling water from the circulation system at a temperature not exceeding 33° C.
Condensing device intended for servicing the turbine installation, it consists of a condenser, main and starting ejectors, condensate and circulation pumps and water filters.
Surface two-pass condenser with a total cooling surface of 3,000 m 2 is designed to operate on fresh cooling water. It provides a separate built-in bundle for heating make-up or network water, the heating surface of which is about 20% of the entire surface of the condenser.
An equalizing vessel is supplied with the condenser for connecting an electronic level controller sensor that acts on the control and recirculation valves installed on the main condensate pipeline. The condenser has a special chamber built into the steam part, in which HDPE section No. 1 is installed.
The air removal device consists of two main three-stage ejectors (one backup), designed to suck air and ensure the normal heat exchange process in the condenser and other vacuum heat exchange devices, and one starting ejector to quickly raise the vacuum in the condenser to 500-600 mm Hg. Art.
Two condensate pumps (one backup) of a vertical type are installed in the condensation device to pump out condensate and supply it to the deaerator through ejector coolers, seal coolers and HDPE. Cooling water for the condenser and generator gas coolers is supplied by circulation pumps.
For mechanical purification of cooling water supplied to the oil coolers and gas coolers of the unit, filters with rotating screens are installed for on-the-fly washing.
The starting ejector of the circulation system is designed to fill the system with water before starting the turbine unit, as well as to remove air when it accumulates in high points drain circulation conduits and in the upper water chambers of oil coolers.
To break the vacuum, an electric valve is used on the air suction pipeline from the condenser, installed at the starting ejector.
Regenerative device designed to heat feed water (turbine condensate) with steam taken from the intermediate stages of the turbine. The installation consists of a surface working steam condenser, a main ejector, surface steam coolers made of labyrinth seals, surface HDPE, after which the turbine condensate is sent to the surface HDPE deaerator to heat the feed water after the deaerator in an amount of about 105% of the maximum turbine steam flow.
HDPE No. 1 is built into the condenser. The remaining HDPEs are installed by a separate group. HPH Nos. 5, 6 and 7 - vertical design with built-in desuperheaters and drainage coolers.
HPHs are equipped with group protection, consisting of automatic outlet and check valves at the water inlet and outlet, an automatic valve with an electromagnet, a pipeline for starting and shutting down the heaters.
Each HDPE and HDPE, except HDPE No. 1, is equipped with a condensate drain control valve controlled by an electronic “regulator”.
Draining heating steam condensate from heaters is cascade. From HDPE No. 2, condensate is pumped out by a drain pump.
Condensate from PVD No. 5 is directly sent to the deaerator 6 kgf/cm 2 abs. or if there is insufficient pressure in the heater at low turbine loads, it automatically switches to draining into the HDPE.
The characteristics of the main equipment of the regenerative installation are given in Table. 4.
To extract steam from the outer compartments of the turbine labyrinth seals, a special vacuum cooler SP is supplied.
Steam is suctioned from the intermediate compartments of the turbine labyrinth seals into a vertical CO cooler. The cooler is included in the regenerative circuit for heating the main condensate after HDPE No. 1.
The design of the cooler is similar to that of low-pressure heaters.
Heating of network water is carried out in an installation consisting of two network heaters No. 1 and 2 (PSG No. 1 and 2), connected in pairs to the lower and upper heating outlets, respectively. Type of network heaters is PSG-1300-3-8-1.
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Equipment identification |
Heating surface, m 2 |
Work Environment Settings |
Pressure, kgf/cm 2 abs., at hydraulic test in spaces |
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Water consumption, m 3 / h |
Resistance, m water. Art. |
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Built into the capacitor |
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HDPE No. 2 |
PN-130-16-9-II |
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HDPE No. 3 |
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HDPE No. 4 |
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HDPE No. 5 |
PV-425-230-23-1 |
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HDPE No. 6 |
PV-425-230-35-1 |
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HDPE No. 7 |
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Steam cooler from intermediate seal chambers |
PN-130-1-16-9-11 |
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Steam cooler from seal end chambers |
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- Tutorial
Preface to the first part
Modeling steam turbines is a daily task for hundreds of people in our country. Instead of a word model it's common to say flow characteristic. The flow characteristics of steam turbines are used to solve such problems as calculating the specific consumption of equivalent fuel for electricity and heat produced by thermal power plants; optimization of CHP operation; planning and maintaining CHP modes.
Developed by me new flow characteristics of a steam turbine— linearized flow characteristic of a steam turbine. The developed flow characteristic is convenient and effective in solving these problems. However, at the moment it is described only in two scientific works:
- Optimization of the operation of thermal power plants in the conditions of the wholesale electricity and capacity market in Russia;
- Computational methods for determining the specific consumption of equivalent fuel from thermal power plants for supplied electrical and thermal energy in the combined generation mode.
And now in my blog I would like to:
- firstly, in a simple and accessible language, answer the main questions about the new flow characteristic (see Linearized flow characteristic of a steam turbine. Part 1. Basic questions);
- secondly, provide an example of constructing a new flow characteristic, which will help to understand both the construction method and the properties of the characteristic (see below);
- thirdly, to refute two well-known statements regarding the operating modes of a steam turbine (see Linearized flow characteristic of a steam turbine. Part 3. Debunking myths about the operation of a steam turbine).
1. Initial data
The initial data for constructing a linearized flow characteristic can be
- actual power values Q 0 , N, Q p, Q t measured during the operation of the steam turbine,
- nomograms q t gross from regulatory and technical documentation.
In cases where the actual values of Q 0 , N, Q p, Q t are not available, nomograms q t gross can be processed. These, in turn, were obtained based on measurements. Read more about turbine testing in V.M. Gornshtein. and etc. Methods for optimizing power system modes.
2. Algorithm for constructing a linearized flow characteristic
The construction algorithm consists of three steps.
- Translation of nomograms or measurement results into tabular form.
- Linearization of the flow characteristic of a steam turbine.
- Determination of the boundaries of the control range of steam turbine operation.
When working with nomograms q t gross, the first step is carried out quickly. This kind of work is called digitization(digitizing). Digitizing 9 nomograms for the current example took me about 40 minutes.
The second and third steps require the use of mathematical packages. I love and have been using MATLAB for many years. My example of constructing a linearized flow characteristic is made exactly in it. The example can be downloaded from the link, run and independently understand the method of constructing a linearized flow characteristic.
The flow characteristic for the turbine under consideration was plotted for the following fixed values of the mode parameters:
- single-stage operating mode,
- medium pressure steam pressure = 13 kgf/cm2,
- low pressure steam pressure = 1 kgf/cm2.
1) Nomograms of specific consumption q t gross for electricity generation (the marked red dots are digitized and transferred to the table):
- PT80_qt_Qm_eq_0_digit.png,
- PT80_qt_Qm_eq_100_digit.png,
- PT80_qt_Qm_eq_120_digit.png,
- PT80_qt_Qm_eq_140_digit.png,
- PT80_qt_Qm_eq_150_digit.png,
- PT80_qt_Qm_eq_20_digit.png,
- PT80_qt_Qm_eq_40_digit.png,
- PT80_qt_Qm_eq_60_digit.png,
- PT80_qt_Qm_eq_80_digit.png.
2) Digitization result(each csv file has a corresponding png file):
- PT-80_Qm_eq_0.csv,
- PT-80_Qm_eq_100.csv,
- PT-80_Qm_eq_120.csv,
- PT-80_Qm_eq_140.csv,
- PT-80_Qm_eq_150.csv,
- PT-80_Qm_eq_20.csv,
- PT-80_Qm_eq_40.csv,
- PT-80_Qm_eq_60.csv,
- PT-80_Qm_eq_80.csv.
3) MATLAB script with calculations and graphing:
- PT_80_linear_characteristic_curve.m
4) The result of digitizing nomograms and the result of constructing a linearized flow characteristic in tabular form:
- PT_80_linear_characteristic_curve.xlsx.
Step 1. Translation of nomograms or measurement results into tabular form
1. Processing of initial data
The initial data for our example are nomograms q t gross.
To convert many nomograms into digital form, a special tool is needed. I have used the web application many times for these purposes. The application is simple and convenient, but does not have enough flexibility to automate the process. Some of the work has to be done manually.
At this step, it is important to digitize the extreme points of the nomograms, which set the boundaries of the control range of the steam turbine.
The work consisted of marking the points of the flow characteristic in each png file using the application, downloading the resulting csv and collecting all the data in one table. The result of digitization can be found in the file PT-80-linear-characteristic-curve.xlsx, sheet “PT-80”, table “Initial data”.
2. Conversion of units of measurement to units of power
$$display$$\begin(equation) Q_0 = \frac (q_T \cdot N) (1000) + Q_P + Q_T \qquad (1) \end(equation)$$display$$
and reduce all initial values to MW. Calculations are carried out using MS Excel.
The resulting table “Initial data (units of power)” is the result of the first step of the algorithm.
Step 2. Linearization of the steam turbine flow characteristic
1. Checking the operation of MATLAB
At this step you need to install and open MATLAB version no lower than 7.3 (this old version, current 8.0). In MATLAB, open the file PT_80_linear_characteristic_curve.m, run it and make sure it works. Everything works correctly if, after running the script in command line you saw the following message:
Values were read from the file PT_80_linear_characteristic_curve.xlsx for 1 second Coefficients: a(N) = 2.317, a(Qп) = 0.621, a(Qт) = 0.255, a0 = 33.874 Average error = 0.006, (0.57%) Number of boundary points of the adjustment range = 37
If you have any errors, figure out how to fix them yourself.
2. Computations
All calculations are implemented in the file PT_80_linear_characteristic_curve.m. Let's look at it in parts.
1) Specify the name of the source file, sheet, range of cells containing the “Initial data (unit of power)” table obtained in the previous step.
XLSFileName = "PT_80_linear_characteristic_curve.xlsx"; XLSSheetName = "PT-80"; XLSRange = "F3:I334";
2) We calculate the initial data in MATLAB.
sourceData = xlsread(XLSFileName, XLSSheetName, XLSRange); N = sourceData(:,1); Qm = sourceData(:,2); Ql = sourceData(:,3); Q0 = sourceData(:,4); fprintf("Values read from file %s in %1.0f sec\n", XLSFileName, toc);
We use the variable Qm for the average pressure steam flow Q p, index m from middle- average; similarly we use the variable Ql for low pressure steam flow Qn, index l from low- short.
3) Let's determine the coefficients α i .
Let us recall the general formula for the flow characteristics
$$display$$\begin(equation) Q_0 = f(N, Q_P, Q_T) \qquad (2) \end(equation)$$display$$
and indicate the independent (x_digit) and dependent (y_digit) variables.
x_digit = ; % electricity N, industrial steam Qп, district heating steam Qт, unit vector y_digit = Q0; % live steam consumption Q0
If you don’t understand why there is a unit vector (last column) in the x_digit matrix, then read the materials on linear regression. On the topic of regression analysis, I recommend the book Draper N., Smith H. Applied regression analysis. New York: Wiley, In press, 1981. 693 p. (available in Russian).
Equation of the linearized flow characteristic of a steam turbine
$$display$$\begin(equation) Q_0 = \alpha_N \cdot N + \alpha_P \cdot Q_P + \alpha_T \cdot Q_T + \alpha_0 \qquad (3) \end(equation)$$display$$
is a multiple linear regression model. We will determine the coefficients α i using "great benefit of civilization"— least squares method. Separately, I note that the least squares method was developed by Gauss in 1795.
In MATLAB this is done in one line.
A = regress(y_digit, x_digit); fprintf("Coefficients: a(N) = %4.3f, a(Qп) = %4.3f, a(Qт) = %4.3f, a0 = %4.3f\n",... A);
Variable A contains the desired coefficients (see message on the MATLAB command line).
Thus, the resulting linearized flow characteristic of the PT-80 steam turbine has the form
$$display$$\begin(equation) Q_0 = 2.317 \cdot N + 0.621 \cdot Q_P + 0.255 \cdot Q_T + 33.874 \qquad (4) \end(equation)$$display$$
4) Let us estimate the linearization error of the resulting flow characteristic.
y_model = x_digit * A; err = abs(y_model - y_digit) ./ y_digit; fprintf("Mean error = %1.3f, (%4.2f%%)\n\n", mean(err), mean(err)*100);
Linearization error is 0.57%(see message on MATLAB command line).
To assess the ease of use of the linearized flow characteristic of a steam turbine, let us solve the problem of calculating the flow rate of high-pressure steam Q 0 at known values loads N, Q p, Q t.
Let N = 82.3 MW, Q p = 55.5 MW, Q t = 62.4 MW, then
$$display$$\begin(equation) Q_0 = 2.317 \cdot 82.3 + 0.621 \cdot 55.5 + 0.255 \cdot 62.4 + 33.874 = 274.9 \qquad (5) \end(equation)$$ display$$
Let me remind you that the average calculation error is 0.57%.
Let's return to the question: why is the linearized flow characteristic of a steam turbine fundamentally more convenient than nomograms of specific consumption q t gross for electricity generation? To understand the fundamental difference in practice, solve two problems.
- Calculate the Q 0 value to the specified accuracy using nomograms and your eyes.
- Automate the process of calculating Q 0 using nomograms.
It is obvious that in the first problem, determining the values of q t gross by eye is fraught with gross errors.
The second task is cumbersome to automate. Because the the values of q t gross are nonlinear, then for such automation the number of digitized points is tens of times greater than in the current example. Digitization alone is not enough, it is also necessary to implement the algorithm interpolation(finding values between points) non-linear gross values.
Step 3. Determining the boundaries of the control range of the steam turbine
1. Calculations
To calculate the adjustment range we will use another "a blessing of civilization"— convex hull method, convex hull.
In MATLAB this is done as follows.
indexCH = convhull(N, Qm, Ql, "simplify", true); index = unique(indexCH); regRange = ; regRangeQ0 = * A; fprintf("Number of control range boundary points = %d\n\n", size(index,1));
The convhull() method defines limit points of the adjustment range, specified by the values of the variables N, Qm, Ql. The indexCH variable contains the vertices of triangles constructed using Delaunay triangulation. The regRange variable contains the boundary points of the adjustment range; variable regRangeQ0 - high pressure steam flow rates for the boundary points of the control range.
The result of the calculations can be found in the file PT_80_linear_characteristic_curve.xlsx, sheet “PT-80-result”, table “Limits of the adjustment range”.
The linearized flow characteristic has been constructed. It represents a formula and 37 points that define the boundaries (envelope) of the adjustment range in the corresponding table.
2. Check
When automating the processes of calculating Q 0, it is necessary to check whether a certain point with the values N, Q p, Q t is inside the adjustment range or outside it (the mode is not technically feasible). In MATLAB this can be done as follows.
We set the values N, Q p, Q t that we want to check.
n = 75; qm = 120; ql = 50;
Let's check.
in1 = inpolygon(n, qm, regRange(:,1),regRange(:,2)); in2 = inpolygon(qm, ql, regRange(:,2),regRange(:,3)); in = in1 && in2; if in fprintf("Point N = %3.2f MW, Qp = %3.2f MW, Qt = %3.2f MW is within the control range\n", n, qm, ql); else fprintf("Point N = %3.2f MW, Qp = %3.2f MW, Qt = %3.2f MW is outside the control range (technically unattainable)\n", n, qm, ql); end
The check is carried out in two steps:
- the variable in1 shows whether the values of N, Q p fell inside the projection of the shell on the N, Q p axis;
- similarly, the variable in2 shows whether the values of Q p, Q t fell inside the projection of the shell on the Q p, Q t axes.
If both variables are equal to 1 (true), then the desired point is inside the shell, which specifies the control range of the steam turbine.
Illustration of the resulting linearized steam turbine flow characteristic
Most "generous benefits of civilization" we got to illustrate the calculation results.
First of all, we must say that the space in which we build graphs, i.e., the space with axes x - N, y - Q t, z - Q 0, w - Q p, is called regime space(see Optimization of the operation of thermal power plants in the conditions of the wholesale electricity and capacity market in Russia
). Each point in this space determines a certain operating mode of the steam turbine. The mode may be
- technically feasible if the point is inside the shell that defines the adjustment range,
- technically not feasible if the point is outside this shell.
If we talk about the condensation mode of operation of a steam turbine (Q p = 0, Q t = 0), then linearized flow characteristic represents straight segment. If we talk about a T-type turbine, then the linearized flow characteristic is flat polygon in three-dimensional mode space with axes x – N, y – Q t, z – Q 0, which is easy to visualize. For a PT-type turbine, visualization is the most complex, since the linearized flow characteristic of such a turbine represents flat polygon in four-dimensional space(for explanations and examples, see Optimizing the operation of thermal power plants in the conditions of the Russian wholesale electricity and capacity market, section Linearization of turbine flow characteristics).
1. Illustration of the resulting linearized flow characteristic of a steam turbine
Let's construct the values of the table “Initial data (units of power)” in regime space.
Rice. 3. Initial points of the flow characteristic in the regime space with axes x – N, y – Q t, z – Q 0
Since we cannot construct a dependence in four-dimensional space, we have not yet reached such a benefit of civilization, we operate with the values of Q n as follows: we exclude them (Fig. 3), fix them (Fig. 4) (see the code for constructing graphs in MATLAB).
Let us fix the value of Q p = 40 MW and construct the starting points and the linearized flow characteristic.
Rice. 4. Initial points of the flow characteristic (blue points), linearized flow characteristic (green flat polygon)
Let's return to the formula we obtained for the linearized flow characteristic (4). If we fix Q p = 40 MW MW, then the formula will look like
$$display$$\begin(equation) Q_0 = 2.317 \cdot N + 0.255 \cdot Q_T + 58.714 \qquad (6) \end(equation)$$display$$
This model defines a flat polygon in three-dimensional space with axes x – N, y – Q t, z – Q 0 by analogy with a T-type turbine (which we see in Fig. 4).
Many years ago, when nomograms for q t gross were being developed, a fundamental mistake was made at the stage of analyzing the initial data. Instead of using the least squares method and constructing a linearized flow characteristic of a steam turbine, for some unknown reason, a primitive calculation was made:
$$display$$\begin(equation) Q_0(N) = Q_e = Q_0 - Q_T - Q_P \qquad (7) \end(equation)$$display$$
We subtracted the vapor consumption Q t, Q p from the high-pressure steam consumption Q 0 and attributed the resulting difference Q 0 (N) = Q e to electricity generation. The resulting value Q 0 (N) = Q e was divided by N and converted to kcal/kWh, obtaining specific consumption q t gross. This calculation does not comply with the laws of thermodynamics.
Dear readers, maybe you know the unknown reason? Share it!
2. Illustration of the adjustment range of a steam turbine
Let's look at the shell of the adjustment range in the regime space. The starting points for its construction are presented in Fig. 5. These are the same points that we see in Fig. 3, however, the parameter Q 0 is now excluded.
Rice. 5. Initial points of the flow characteristic in the regime space with axes x – N, y – Q p, z – Q t
Many points in Fig. 5 is convex. Using the convexhull() function, we have identified the points that define the outer shell of this set.
Delaunay triangulation(a set of connected triangles) allows us to construct the control range envelope. The vertices of the triangles are the boundary values of the control range of the PT-80 steam turbine we are considering.
Rice. 6. Shell of the adjustment range, represented by many triangles
When we checked a certain point for falling inside the adjustment range, we checked whether this point lay inside or outside the resulting shell.
All graphs presented above were constructed using MATLAB (see PT_80_linear_characteristic_curve.m).
Promising problems associated with the analysis of steam turbine operation using linearized flow characteristics
If you are doing a diploma or dissertation, I can offer you several tasks, the scientific novelty of which you can easily prove to the whole world. In addition, you will do excellent and useful work.
Problem 1
Show how a flat polygon changes when the low-pressure vapor pressure Qt changes.
Problem 2
Show how a flat polygon changes when the pressure in the condenser changes.
Problem 3
Check whether the coefficients of the linearized flow characteristic can be represented as functions additional parameters regime, namely:
$$display$$\begin(equation) \alpha_N = f(p_(0),...); \\ \alpha_P = f(p_(P),...); \\ \alpha_T = f(p_(T),...); \\ \alpha_0 = f(p_(2),...). \end(equation)$$display$$
Here p 0 is the high pressure steam pressure, p p is the medium pressure steam pressure, p t is the low pressure steam pressure, p 2 is the exhaust steam pressure in the condenser, all units are kgf/cm2.
Justify the result.
Links
Chuchueva I.A., Inkina N.E. Optimization of the operation of thermal power plants in the conditions of the wholesale electricity and power market in Russia // Science and education: scientific publication of MSTU im. N.E. Bauman. 2015. No. 8. P. 195-238.
- Section 1. Meaningful formulation of the problem of optimizing the operation of thermal power plants in Russia
- Section 2. Linearization of turbine flow characteristics
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