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PN. ACB-859
96292
Burns and Roe Enterprises, Inc.
Technical Report
KAZAKSTAN EXPANDED ENERGY PROGRAM
HEAT AND POWER SYSTEM EFFICIENCY
IMPROVEMENTS
KARAGANDA & UST-KAMENOGORSK PLANTS
FINAL REPORTS
January 1996
Prepared by:
Burns and Roe Enterprises, Inc.
Submitted to:
U.S. Agency for International Development
The Government of Kazakstan
Contract No. :
CCN-0002-Q-09-3154-00
Heat and Power System Efficiency Improvements
Delivery Order No.9, Task 2
A
Burns and Roe Company
800 Kinderkamack Road. Oradell. New Jersey 07649
(201) 265-2000 Telecopier (201) 986-1459 Telex 215058 Caple BURNS RCE ORA
January 30, 1996
Mr. Iqbal Chaudhry
Energy Officer
U.S. Agency for International Development
AID/EEUD/E&I/EI
Room 440 - NS, Department of State
320 21 st Street NW
Washington, D.C. 20523
Subject:
Kazakstan - Final Report
Expanded Energy Program
Heat and Power System Efficiency Improvements
Karaganda and Ust-Kamenogorsk Plants
Dear Mr. Chaudhry:
In January 1995, Burns and Roe started a study in Kazakstan to determine Heat and
Power Plant Efficiency Improvements. Four plants were selected for the study by
Kazakstan's Ministry of Energy and Coal, and Kazakstanenergo, namely:
Ermakovskaya in Pavlodar, block 3
Ekibastuz #1, block 3
Karaganda #2, block 3
Ust - Kamenogorsk, block 7
This final report submittal covers Karaganda and Ust-Kamenogorsk plants.
Ermakovskaya and Ekibastuz final reports were submitted to your officeon January 19,
1996.
Enclosed please find 3 copies of the subject report. Also, a copy of the report is being
forwarded to Mr. Barry Primm, USAID Almaty Mission.
All comments generated by USAID (Almaty Mission and Rolf Manfred) and Kazakstan's
Ministry of Energy and Coal, and Kazakstanenergo have been incorporated into the final
edition.
Achievements S engineering and construct 1932
Mr. Iqbal Chaudhry
January 30, 1996
Page -2-
In addition, please be advised that the subject report has been translated to Russian and it
is also being distributed in Almaty to the Ministry of Energy and Coal and
Kazakstanenergo.
Please let me know if you have any questions.
Sincerely,
N Paping
N. Popovic
Project Director
cc:
All w/att
G. Weynand, USAID
B. Primm, USAID, Almaty
S. Gerges, Burns and Roe
C
TABLE OF CONTENTS
KAZAKSTAN EXPANDED ENERGY PROGRAM
TASK 2
HEAT AND POWER SYSTEM EFFICIENCY IMPROVEMENT
KARAGANDA POWER PLANT
1.0
Introduction and Objective
2.0
Kazakstan Energy Sector Strategy
3.0
Plant Description and Evaluation
3.1
Steam Boilers
3.2
Steam Turbine/Generators
3.3
Auxiliary Plant Systems
3.4
Instrumentation and Controls
3.5
Air Pollution Controls
3.6
District Heating System
4.0
Plant Rehabilitation Recommendations
4.1
Steam Boilers
4.2
Steam Turbine/Generators
4.3
Auxiliary Plant Systems
4.4
Instrumentation and Controls
4.5
Air Pollution Controls
4.6
District Heating System
4.7
Rehabilitation Benefits
5.0
Capital Cost Estimates
6.0
Construction Schedule
5909-98A/KARA-TOC.DOC/2/5/96
i
ABBREVIATIONS
CIS
Community of Independent States
USAID
U.S. Agency for International Development
CCE
Capital Cost Estimate
CHP
Combined Heat and Power
TES
Thermal Electric Station
LHV
Lower Heating Value
OD
Outside Diameter
PA
Primary Air
PC
Pulverized Coal
NDE
Non Destructive Examination
HP
High Pressure
IP
Intermediate Pressure
LP
Low Pressure
NO,
Nitrogen Oxides
SO₂
Sulfur Dioxide
ESP
Electrostatic Precipitators
I&C
Instrumentation and Controls
OFA
Overfire air or bulk furnace air staging
LNB
Low NOx burner
VM
Volatile matter
FC
Fixed carbon
HGI
Hardgrove Grindability Index, HGI = (Kₚ₀ -0.32)/0.0149
BMCR
Boiler Maximum Continuous Rating
LHV
Lower Heating Value
TMCR
Turbine Maximum Continuous Rating
T/G
Turbine Generator
WEIGHTS AND MEASURES
at abs. or g
atmosphere absolute or gage
Gcal
Gigacalorie (10⁹ cal)
MW
Megawatt (10⁶ Watt)
kW
kilowatt (10³ Watt)
kg
kilogram
kV
kilovolt
kWh
kiloWatt hour
MVAR
Megavolt-Ampere Reactive
kg/cm²
kilograms per square centimeter
t/h or te/h
tons per hour (metric)
RPM
Rotations per minute
BTU
British Thermal Unit
MMBTU
Million BTU heat input
CONVERSION FACTORS
1 GCal = 4.187 GJ = 3.968 X 10⁶ BTU = 1,163 kWh
5909-98A/KARA-TOC.DOC/2/5/96
ii
1.0
INTRODUCTION AND OBJECTIVE
The dissolution of the Soviet Union in 1991 resulted in the formation of five new independent
republics in Central Asia: Kazakstan, Kyrgyzstan, Uzbekistan, Turkmenistan and Tajikistan. Of
these, Kazakstan is the largest republic in terms of physical size and second largest in population.
Its physical size (area) is more than the area of the other four republics combined.
Kazakstan is a vast country with an abundance of valuable resources, including abundant energy
reserves and a large industrial base. Unfortunately, the collapse of the former Soviet Union has
resulted in economic dislocations throughout the central Asian republics including Kazakstan.
The transition from a command economy to a market economy has been painful to the population.
Industries which are no longer subsidized and protected by the former Soviet Union must be able
to survive in a more competitive market place. This has resulted in a severe economic recession.
The current economic recession has adversely affected the country's economy, including the
slowdown in the energy industries.
The majority of the thermal and heating plants in Kazakstan are over 20 years old and are
operating with obsolete equipment or with components requiring renovation. Maintenance
schedules do not allow for high availability of the units. In addition, many plants are obliged to
fire non-design fuel (e.g. coal with ash content exceeding the maximum design specification).
These problems combine to decrease power and heat production levels by as much as 20-40%
from the design capacities. The impact of the reduced power production has been moderated in
the past few years by a decrease in demand due to industrial recession. Reduced heat production
often results in domestic heating black-outs.
The shortfall in energy production will continue if the plants are not rehabilitated in the future; and
as Kazakstan grows into a market-led economy, the demand will accelerate and lack of available
energy will, potentially, become the limiting factor in the economic development of the country.
Increasing the efficiency of existing plants, extending their life and implementing a consumer
energy saving program are the most cost effective means for increasing energy independence.
However, the necessary renovation and maintenance costs are large. A plan for a consumer
energy savings program is being developed separately by a joint effort of the Ministries of
Economy and the Ministry of Energy and Coal. This separate effort is also supported by USAID
USAID has recognized the seriousness of these problems, and has authorized this task for Burns
and Roe to assess the situation relative to Heat and Power Plant Efficiency Improvements. The
work covered by this report addresses the assessment of selected units at four different locations
in Kazakstan. The Karaganda Electric Generation (Power) Plant is one of the selected plants for
energy efficiency improvements study.
The objective of this project is to assess the costs and benefits of the efficiency and energy
production improvements which can be achieved by renovating and extending the life of the
5909-98A/KARA.DOC/2/8/96
1
selected units. This report may serve as a basis for domestic and foreign investment
considerations.
The work covered by this report included the following tasks:
Background data related to the project was collected and analyzed. Meetings
were held with Kazakstani engineers to discuss the collected data.
A condition assessment was performed to determine the thermal efficiency of the
system and identify the major plant systems and components which require
rehabilitation or modernization.
An engineering analysis was performed to recommend modern technology for
increasing the availability and performance of the selected unit. This analysis also
includes development of capital cost estimates and implementation schedules.
A detailed rehabilitation and modernization program is outlined and
recommendations are made for life extension of the unit.
A review of the Karaganda District Heating System piping was made with District
Heating system engineers. Recommendations were developed to improve system
efficiency and reliability based on the information provided by the DH system
engineers.
The results of the engineering analysis will be reviewed with Kazakstani
authorities. The Kazakstani authorities may extrapolate the results of this analysis
to other fossil plants in the country.
5909-98A/KARA.DOC/2/8/96
2
2.0
KAZAKSTAN ENERGY SECTOR STRATEGY
The Kazakstan Power System currently consists of 64 electric power stations with a total capacity
of 16,026 MWe. These 64 plants include 40 Thermal Electric Power Stations (TES), with a
capacity of 13,897 MWe. The other 24 plants are electric generating stations and hydroelectric
power stations. The TES units provide district heat and/or process steam to industries in addition
to electric power generation whereas the remaining 24 plants only provide electric power. The
main fuel used in these plants is coal. A breakdown of the fuel usage is shown below:
Fuel
Percent
Coal
74.3%
Petroleum (Oil, etc.)
12.2%
Natural Gas
14.5%
The main goals of Kazakstan Energo, as determined by the Ministry of Energy and Fuel
Resources are:
1.
To refurbish the current power plants operating in Kazakstan to improve their
efficiency, reliability, and reduce emissions to the environment.
2.
To commission new generating facilities with environmental controls to meet the
future shortfall in production capacities.
3.
To institute energy savings and conservation programs for consumers of heat and
electricity.
4.
To upgrade the current power plants with state of the art technology.
5.
To gradually bring the prices of heat and electricity up to the current world price
levels in a transition to a market based economy.
6.
To develop a new management structure for the power, heat generation, and
distribution industry.
Kazakstan currently imports electricity from Russia and other central Asian countries. In 1992,
Kazakstan imported 14 billion kWh of electricity. The gap between demand and installed capacity
is approximately 2,000 MW. Thus, there is a great need to install new generating capacity and to
refurbish the existing plants. Over the next 20 years, Kazakstan plans to create a reserve capacity
of approximately 20 to 25 percent.
During this period of upgrading and installing new capacities, a major focus will be placed on
environmental issues and energy conservation. As new legislation is enacted to help preserve the
5909-98A/KARA.DOC/2/8/96
3
environment, the power sector must upgrade its environmental control equipment at heat and
power generating stations. Installation of NOx and SO₂ reducing technologies and improved ash
collection equipment will be required on all new and refurbished power plants. Improvements in
system thermal efficiency will also contribute to reduced emissions by reducing fossil fuel
consumption.
The amount of pollutants released into the atmosphere can also be reduced by instituting energy
conservation programs as these programs would result in curtailing energy demand and hence
energy production. These programs could consist of gradual increase in tariffs on electric and
thermal energy, sanctions on the irrational use of energy resources, incentives to utilities that
conserve energy, and installation of more energy efficient appliances and industrial processes.
Another benefit of energy conservation program is the decreased demand for new energy
production capacities which will defer the capital investment for construction of new facilities into
the future. This will result in substantial financial benefit to the power generation industry in
Kazakstan.
5909-98A/KARA.DOC/2/8/96
4
3.0 PLANT DESCRIPTIONS AND EVALUATIONS
General
The Karaganda GRES #2 plant was commissioned and placed into service from 1962 to 1967.
The plant has seven turbine generators which provide 608 MW of electrical power and 435 Gcal/h
of heating steam extraction capability. All the turbines in the plant are supplied with main steam
from a 90 ata main steam header. This header carries steam from sixteen pulverized coal boilers.
These boilers have a combined steaming capacity of 3520 t/h.
The plant is subdivided into two sections. The first section consists of six type PK-10p-2 boilers
and three turbine generators. One of the turbines is type K-50-90 with 50 MW electric generating
capacity, while the other two are model K-100-90 with 100 MW electric generating capacity
each. This section of the plant can generate 250 MW of electricity. The second section of the
plant consists of nine boilers type PK-10p-2 and one boiler type PK-14-3. The second section
also contains four turbine generators, three T-86-90/2.5 and one K-100-90. This section can
generate 358 MW of electricity and 300 Gcal/h of heat for district heating. The remaining 135
Gcal/h of heating steam is provided from pressure reducing stations which take steam from the
main header and reduce its pressure so the steam can be used in the district heating heat
exchangers.
The plant management and the Burns and Roe team has jointly selected turbine No. 3 and boilers
7, 10, and 13 for further evaluation as a part of the renovation project for this plant.
3.1
STEAM BOILERS
The fifteen (15) PK-10p-2 boilers of Karaganda GRES #2 are nearly identical. Boiler 16 is type
PK-14-3 with only 66,000 hours operating time. This boiler has not been included in this analysis
due to its young age. Each boiler is of the natural circulation drum type, with a radiant balanced
draft, dry bottom furnace. The boiler configuration is of the conventional two-pass without a
furnace arch, a short horizontal convective pass, and a vertical rear-pass. The boilers were
designed for operation in a combined heat and power (CHP) plant. The furnace is rectangular.
9785 mm wide and 7600 mm deep. The furnace tubewalls are fully water cooled, 76 mm OD by
6 mm nominal thickness carbon steel tubes on 95 mm centers, with refractory backing. The
horizontal and rear convective passes rooftubes are steam cooled, 42 mm OD by 4.5 mm thick.
and are also made of carbon steel material. Each boiler has two (2) steam/water drums, with
1300 and 300 mm ID's, both are made of carbon steel material. The downcomers are small
diameter (108 mm OD by 7 mm thick) pipes. The horizontal short convective pass sidewalls and
floor, the rear convective pass top portion front, rear and sidewalls, and the economizer
enclosures in the vertical rear pass are refractory brick lined. The tubular airheater stages in the
rear convective pass have metal casings.
The furnace is tangentially fired and has an indirect firing system. The boilers fuel/air injectors
(burners) are positioned in the furnace sidewalls, each sidewall has two (2) pulverized
5909-98A/KARA.DOC/2/8/96
5
coal/primary air injection port levels with the secondary air injection ports positioned above and
below each coal injector with a total of eight (8) coal injection nozzles per boiler.
The superheater heating surfaces can be divided into radiant and convective parts. The radiant
primary superheater (SH) consists of the furnace and convective passes roof tubes. The
convective, pendant primary and secondary superheaters are positioned in the horizontal
convective pass. Steamflow is divided into two parallel paths, with a steam side crossover
between the 1st and 2nd stage SHs.
Superheated steam final temperature control is by spray attemperation. Drum saturated steam is
condensed by feedwater prior to entering the 1st stage economizer. The steam condenser
discharge water enters the 1st stage economizer, the condensate is then injected into the spray
nozzles of the steam attemperators which are positioned between the 1st and 2nd stage of the
superheater. The economizer (1st and 2nd stages) consists of horizontal fully drainable tube
banks of bare staggered tubes, 32 mm OD by 3.5 mm thick and are made of carbon steel material.
The water is in upflow and the fluegas is in downflow. Both economizer stages are positioned in
the vertical rear convective pass. The economizer has a recirculation line installed. The tubular
airheater (1st and 2nd stages) is also positioned in the rear convective pass, with fluegas in the
tubes in downflow and combustion air in upflow across the tubes. The air heater has staggered
tubes of 51 mm OD by 1.5 mm thick which are made of carbon steel material. Cold end corrosion
protection of the airheater is provided by hot air recirculation into the FD fan suction side.
The draft plant of each boiler consists of two (2) forced draft (FD) and two (2) induced draft (ID)
fans. The forced draft fans are the radial flow centrifugal type, with radial inlet vane control, and
a constant speed electric motor drive. The induced draft fans are radial flow, centrifugal type with
inlet louver damper control and constant speed electric motor drive.
The indirect firing system of each boiler consists of two (2) raw coal silos each with a dedicated
volumetric coal feeder, two (2) tumbling ball mills size SBM 287/470 S-16 each with an external
centrifugal classifier, two (2) ball mill exhauster fans of radial flow, (centrifugal type with constant
speed electric motor drive) two (2) separating cyclones, a common pulverized coal storage
bunker with pc feeders, PC/PA and hot PA conduits and dampers, hangers, etc. The ball mills
operate with subatmospheric pressure. Each exhauster fan conveys the PA/PC mixture to one
level of four (4) furnace coal injectors. The forced draft fans provide the hot PA supply to the
ball mill inlets and also the cold tempering air for maintaining a constant classifier exit PA/PC
mixture temperature. Cold tempering air can also be injected into the exhauster fans suction side.
Particulate emission control equipment consists of four (4) wet scrubbers per boiler on boilers I
to 6 and electrostatic precipitators (ESP) for boilers 7 to 15. There are no provisions made for
reducing NO, and/or SOx emissions. The boilers do not have continuous emission monitoring
equipment installed.
Heating surface cleaning equipment consisting of steam operated furnace wall blowers and also
retractable steam operated sootlances in the horizontal convective passes have been removed from
the PK-10p-2 boilers. With the presently fired Ekibastuz bituminous coal their use is not needed.
5909-98A/KARA DOC/2/8/96
6
The furnace operates at all loads without any severe slag type wall deposits and the highly erosive
flyash cleans the convective surfaces of any fouling type deposits. Bottom ash handling
equipment consists of a refractory lined, water impounded bottom ash hopper supported on the
basement floor with a screw type slag discharge device feeding into the basement floor ash sluice
system.
The boiler furnace, short horizontal convective pass, and top of the vertical convective pass are
top supported, and the rest of the vertical convective pass is bottom supported, with a metallic
expansion joint in-between. The main and surge steam/water drums are bottom supported from
the boiler suspension steel structure. The table below, (TABLE 3-1) shows the major operating
parameters of the boilers described.
TABLE 3-1
Thermal Performance Design vs Current
Parameter
Units
Design
Current
Live steam flow @ BMCR
te/h
220
166~206
Live steam pressure
at.abs.
100
97~102
Superheated steam temperature (derated)
°C
520
519~527
Feedwater temperature to economizer
°C
215
160~204
Combustion air temperature to airheater
°C
30
18-40
Fluegas temperature leaving airheater
°C
140
152~219
Excess air in fluegas @ economizer exit
%
20
21~25
Combustion air XS @ FD fan discharge
%
40
32-37
Boiler efficiency LHV basis
%
91.8
84.5~87.5
All the boilers are of the subcritical steam pressure type with a drum, thermosyphonic circulation,
no reheater and are manufactured by Podolsk Machine Building Factory. Boilers 1 to 15 have an
average operating times of 200,000 hours each, as of Sept. 1995.
The firing system consists of single flame envelop tangential burners with two (2) levels of
pulverized coal injection nozzles, and indirect (pulverized coal storage) type firing system. The
design fuel was Karaganda coke preparation plant bituminous coal concentrate with a (by weight)
38% mineral matter ash content, 8.5% moisture content, 36.5% VM as fired, LHV of 4003
kcal/kg as fired, HGI of 72 and an ash softening temperature of 1400 to 1500°C. Presently fired
coal is also bituminous from the Ekibastuz open cast mine with a 41 to 44% (by weight) mineral
matter content and 4.5 to 6% moisture content, 24.4% (by weight) VM as fired, LHV of 3560 to
3900 kcal/kg as fired, HGI of 76 and an ash softening temperature over 1500°C. Auxiliary fuel
5909-98A/KARA.DOC/2/8/96
7
for start-ups/shutdowns and combustion stabilization is mazut with an approximate heat input
capacity of 18% of full load heat input. Ignitors are steam atomized. It is proposed that three
(3) PK-10p-2 boilers 7, 10 and 13 from the second power plant section should be
refurbished, to provide full TCMR steamflow to the turbine generator no. 3, with one
boiler in stand-by mode.
Condition Assessment
From the information received, the following assessments can be made:
Creep and low cycle fatigue type failures of water and steam cooled thickwalled pressure
parts and tubing.
High mineral matter content of Ekibastuz coal and metal loss of convective heating
surface tubebanks by highly erosive flyash.
Milling circuit components, e.g. mill exhausters, PA/PC conduits, ball mill liners,
classifiers and separating cyclones erosive wear.
Unmeasured air ingress into boiler setting through horizontal convective pass rooftubes
and vertical convective pass tubes penetration seals.
Boiler setting (refractory, insulation, casing) deterioration. This is another significant
source of false air ingress into the boiler.
Induced draft (ID) fans housing and impeller erosive wear.
Air and fluegas duct systems metallic expansion joints fatigue type failures and fluegas
duct systems wear by highly erosive flyash.
Tubular airheater cold end, also fluegas ducting low temperature corrosion attack.
3.2
STEAM TURBINE GENERATORS
General
The Karaganda GRES-2 plant started its operation in 1962 as a purely electric generating station.
At its completion the plant had two 50 MW (K-50-90) and six 100 MW (K-100-90) condensing
steam turbines. Each of the steam turbines were designed as non-reheat units with main steam
parameters of 90 ata and 535°C. Even though the steam turbines were not district heating
turbines, Units 1 through 6 had a capability for providing a small quantity (about 7.0 Gcal/h each)
of thermal energy from a non-regulated extraction port which also supplied steam to one of the
eight regenerative feedwater heaters in the steam cycle. The bank of steam to water heat
exchangers using extraction steam from these ports was initially used to provide hot water heat to
5909-98A/KARADOC/2/8/96
8
the local village called Topar in addition to the plant's own needs. At that time the nominal power
generation capability of the plant was 700 MW.
As the need for thermal energy grew in the vicinity of the GRES-2 power plant, it became
necessary to make modifications to the steam turbines in order to extract more steam to satisfy
the increased heat demand. Therefore, the last three units were reconstructed to remove large
quantities of steam from the turbine crossover pipes to provide 100 Gcal/h heat from each of
these units. The modifications for turbines No. 7 and 8 were completed in 1979 and the
reconstruction of turbine No. 6 was performed in 1985. Because of these modifications and the
extraction of 100 Gcal/h heat, the designations of these turbines were changed from K-100-90 to
T-86-90/2.5 indicating that the nominal electrical output of these units have been derated to 86
MW.
At the time of the Burns and Roe team visit, the first 50 MW unit had been decommissioned
because of its age, and therefore the current nominal electrical output capability of the plant is 608
MW. The current nominal output of the various steam turbines and the accumulated total number
of operating hours are shown in TABLE 3-2.
5909-98A/KARA.DOC/2/8/96
9
TABLE 3-2
GENERATING CAPABILITY OF THE KARAGANDA GRES-2 TURBINES
Steam Turbine No.
2
3
4
5
6
7
8
Date of Original
8/62
1/63
9/83
10/64
6/65
12/65
7/67
Startup
Original Designation
K-50-90
K-100-90
K-100-90
K-100-90
T-100-90
T-100-90
T-100-90
Current Designation
K-50-90
K-100-90
K-100-90
K-100-90
K-86-90/2.5
T-86-90/2.5
T-86-90/2.5
Nominal Generating
50/0
100/0
100/0
100/0
86/100
86/100
86/100
Capability MW/Gcal/h
Accumulated
249,621
243,054
240,173
231,338
230,124
228,363
221,690
Operating Hours
Number of Capital
10
9
8
9
6
6
6
repairs
Year of last capital
1992
1991
1994
1990
1993
1991
1993
repair
10
From the previous table (TABLE 3-2) it can be seen that the steam turbines have a combined
official nominal heat supply capability of 300 Gcal/h. The heat content of the controlled
extraction steam is transferred to the district heating water in large newer district heating heat
exchangers. The small heat exchangers utilizing unregulated steam extractions are no longer
used.
Technical information received from the plant indicates that currently there are three separate
district heating systems served by the plant. These and their maximum demands are shown below:
System
Current Maximum Demand (Gcal/h)
Topar
63.4
Greenhouses ("The 60-yr USSR")
172.1
The Town of Abai
150.5
Total:
386.0
There is also a small demand of heat (3 Gcal/h) which must be supplied in the form of steam.
Together with the plant's own needs there is a total thermal demand of 412.8 Gcal/h. The plant
currently has a nominal thermal output capability of 435 Gcal/h. However, the thermal demand in
excess of the turbines' 300 Gcal/h capability is satisfied by the use of various pressure reducing
stations. The plant data indicates that the current deficit in efficient hot water supply capability is
about 86 Gcal/h.
The actual plant operating data for the months of 1994 is summarized in TABLE 3-3. From this
table it can be seen that the total electric power generation was 3.97278 X 10⁹ kWh and the
thermal energy generation was 926,410 Gcal in 1994. The individual contribution of the steam
turbines to the above total figures as well as other yearly average plant parameters are shown in
TABLE 3-4.
5909-98A/KARA.DOC/2/8/96
11
TABLE 3-3
SEASONAL GENERATION AND LOADS FOR KARAGANDA GRES-2
(1994)
Electrical
Thermal Energy
Generation
Peak Load
Average Load
Gen.
MONTH
(10³ kWh)
(MW)
(MW)
(Gcal)
January
409,846
625
551
166,904
February
383,901
615
571
154,776
March
410,144
610
551
140,776
April
283,165
535
393
87,367
May
277,821
490
373
26,231
June
295,622
515
411
6,622
July
276,995
500
372
6,872
August
291,491
455
392
6,774
September
269,792
440
375
21,158
October
322,022
525
433
57,634
November
377,501
625
524
105,304
December
374,480
640
503
145,992
5909-98A/KARA.DOC/2/8/96
12
TABLE 3-4
OPERATING PARAMETERS OF THE KARAGANDA TURBOGENERATORS
Unit
2
3
4
5
6
7
8
Electric Power
368,764
686,784
335,104
709,136
644,448
561,792
666,752
Generation 10³ kWh
Average Load, MW
42.5
87.9
93.7
88.0
76.17
80.6
84.2
Thermal Energy
0
0
0
0
225,369
210,028
207,743
Generation, Gcal
Number of hours in
8,760
7,813
3,576
8,055
8,461
6,972
7,923
Operation
Capacity factors, %
Electric
84.19
78.40
38.25
80.95
85.54
74.57
88.50
Thermal
-
-
-
-
25.7
23.99
23.7
Number of Starts
3
4
4
3
3
6
4
Main Steam
92
93
90
90
90
89
91
Pressure, ata
Main Steam
512
515
515
517
513
516
513
Temperature, °C
Vacuum, %
96.5
94.3
95.8
96.0
95.5
95.4
94.7
Condenser Air
15.03
54.75
47.87
12.22
25.47
31.96
34.06
Inleakage, kg/h
Final Feedwater
210
173
213
215
194
213
192
Temperature, °C
Turbine Gross Heat
2,406
2,345
2,279
2,342
2,322
2,073
2,213
Consumption,
kcal/kWh
28"
13
The Karaganda GRES-2 the plant management and the Burns and Roe team together have
selected the No. 3 steam turbine generator for further, more detailed examination and assessment.
Description of the No. 3 Turbine Generator
The Karaganda Unit No. 3 Turbine was placed in service in January, 1963. It is a nominal
100,000 kW, 3000 RPM, non-reheat, tandem compound condensing machine, designed to receive
363 t/h of throttle steam at a pressure of 90 ata and temperature of 535°C at guaranteed full load
conditions. The turbine was designed by LMZ. There are two separate turbine elements on a
single shaft; one single flow high pressure (HP) section, and one double flow low pressure (LP)
section. The cross sectional drawing of the turbine is shown in Figure 3-1.
The HP section of the turbine consists of 20 stages including the Rateau governing stage. The LP
section consist of 5 stages in each flow. There are 8 extraction openings on the turbine
downstream of the 7th, 10th, 13th, 18th and 20th stages in the HP cylinder, and 22nd, 23rd, and
24th stages in the LP cylinder. These uncontrolled extractions provide steam for the turbine
regenerative feedwater heating system. The condensate leaving the main condenser is heated in 5
low pressure heaters, a deaerator, and 3 high pressure heaters. The design temperature of the
final feedwater leaving the highest pressure feedwater heater is 217°C. The thermal cycle
schematic for the No. 3 turbine is shown in Figure 3-2.
In addition to the regenerative feedwater heating steam, the turbine design also allows the
extraction of up to 15 tons per hour of steam from the extraction port which supplies bleed steam
for LP HTR #5. The 15 tons per hour of uncontrolled pressure steam can be utilized in a separate
heat exchanger for producing hot water for district heating purposes.
Main steam to the HP turbine stages is provided from the steam generators through a main steam
stop valve mounted on a separately installed steam chest. Steam from the steam chest flows
through cross pipes to 4 governor valves which are installed on the HP section above the nozzle
boxes. The steam exiting the HP section flows to the LP section through two cross-over pipes.
The exhaust steam from the LP section is condensed in a 2-pass condenser at a design
backpressure of 0.035 kg/cm²abs. The design temperature of the circulating water entering the
condenser under nominal load is 10°C.
The combined support-thrust bearing is located at the front of the HP turbine section. The other
bearings are support bearings and are located as shown in Figure 3-1. The rotors of the HP and
LP sections and the generator are connected by semi-flexible couplings.
The rotor disks of the 20 stages in the HP section are forged together with the rotor. The LP
rotor is made up of the shaft with 10 stacked wheels. The turbine is furnished with a turning gear
with an operating speed of 3.5 rpm.
5909-98A/KARADOC/2/8/96
14
Figure 3-1
TURBINE GENERATOR CROSS-SECTION
1819
#75#
ass
3830
14700
3.a. in
Pur 96 Revenues BOURER Typones ЛМЗ X-100-80
15
Figure 3-2
TURBINE CYCLE SCHEMATIC
KARAGANDA CHP PLANT
MAIN STEAM
H.P. TURB
LP. TURB
1
CONDENSATE
PUMP
TO BOILER
L.P. HEATER #1
H.P. HEATER #8
L.P. HEATER #2
H.P. HEATER #7
L.P. HEATER #3
H.P. HEATER #6
L.P. HEATER #4
L.P. HEATER #5
FEEDWATER
PUMP
DEAERATOR
16
The turbine oil system is a combined system both for regulation and for bearing lubrication. The
oil pressure in the regulating system is 20 kg/cm², and in the lubricating system it is 1 kg/cm².
The electric generator is an AC type TVF-100-2 with hydrogen cooling, and is manufactured by
the Electrosila Factory.
Design/Current Performance of Turbine No. 3
The technical characteristics and design parameters of the No. 3 steam turbine are shown in
TABLE 3-5. This table indicates that the turbine main steam parameters are 90 ata and 535°C.
While the turbine is usually operated with the original main steam pressure of 90 ata, the main
steam temperature has been officially lowered to 515°C as of December 1, 1977 by the order of
the Ministry of Power Engineering and Electrification.
The original guarantee performance figures as per the LMZ Turbine Instruction Manual No.
1267A are as follows:
Guaranteed
Generator
Main Steam Flow
Final FW Temp.
Heat Rate
Output
Efficiency
(t/h)
(°C)
(kcal/kWh)
(kW)
(%)
100,000
99.0
363
217
2190
80,000
98.8
284
204
2240
60,000
98.5
212
188
2300
5909-98A/KARADOC/2/8/96
17
TABLE 3-5
TECHNICAL CHARACTERISTICS OF THE STEAM TURBINE
Units
Original Design
Type
-
K-100-90
Nominal Output
MW
100
Main Steam Pressure
kg/cm²(a)
90
Main Steam Temperature
°C
535
Main Steam Flow
t/h
363
Number of Extractions
-
8
Extraction Configuration
-
3HPH+D+5LPH
Condenser pressure
kg/cm²(a)
0.035
Specific Heat Consumption
kcal/kWh
2190
Turbine Manufacturer
-
LMZ
Overall Length of Turbine
meters
14.7
Number of Turbine Bearings
-
4
Generator Model
-
TVF-100-2
Generator Cooling Medium
-
H₂
These figures are based on the original 90 ata and 535°C main steam parameters, a cooling water
flow through the condenser of 16,000 m³/h at an inlet temperature of 10°C with all feedwater
heaters in service. The original guarantee conditions also state that if the main steam parameters
are decreased not lower than 85 ata and 525°C, then the above outputs can still be delivered but at
the expense of increased main steam flows.
Since no current performance tests were available for the No. 3 turbine, operating data and
maintenance performance test data were reviewed in an effort to determine the heat rate
degradation of the turbine. Performance test data was available for a test performed on Turbine 3
during 1991 following the overhaul. This test was based on the lowered main steam temperature
of 515°C, and with the feedwater heaters in service. Following the application of correction
factors, the test data resulted in a maximum output of 101 MW but with a main steam flow of
386.6 t/h. The heat rates obtained at the same outputs as given for the guarantee data (original
design) showed the following comparisons:
5909-98A/KARADOC/2/8/96
18
Heat Rates (kcal/kWh)
Load (MW)
Original Design
1991 Test
100
2190
2251
80
2240
2263
60
2300
2317
The above comparison indicates that the full load turbine heat rate in 1991 following the last
turbine overhaul was about 2.8% worse than the "as new" original design heat rate. However.
this comparison is based on an abbreviated test right after the overhaul, and therefore it does not
reflect the current performance degradation.
In the absence of sufficient performance test data, an estimate of the current heat rate of the
turbine cycle was developed by review of the monthly Technical Report for Karaganda GRES #2
Operation for the months of 1994. This monthly report shows power actually generated, the
average power generation, and a calculated average heat rate for each unit for each month. For
the purpose of this performance estimate, the data given in these reports for February, March, and
December of 1994 was averaged to estimate the actual average heat rate of 2299 kcal/kWh for
the turbine cycle at an average generation rate of approximately 95% of full load during those
months. For the purpose of this assessment, this is taken as the heat rate which reflects the
current condition of the turbine.
The turbine manufacturer's guarantee data was then reviewed to develop an estimate of the "as
new" turbine cycle heat rate at the generation rate of 95% of full load. The manufacturer's
guarantee heat rates for generation rates of 100%, 80%, and 60% of full load were used to
determine an estimated heat rate of 2202 kcal/kWh at 95% load, with the turbine in the "as new"
condition. For the purpose of this assessment, this is taken as the heat rate reflecting the "as new
condition of the turbine.
Average condenser pressure, and main steam pressure and temperature during the operating
months of February, March and December, 1994 were different than the corresponding values
upon which the guarantees were based. To compensate for these differences, a correction of -6
kcal/kWh was applied to the 2299 kcal/kWh estimated current heat rate resulting in a corrected
current heat rate of 2293 kcal/kWh.
With the above correction, the estimated degradation of turbine performance since the turbine
was new is:
2293-2202 x 100 = 4.13%
2202
5909-98A/KARA.DOC/2/8/96
19
It should be noted that based on the average yearly operating data for 1994 the turbine actual heat
rate is 2345 kcal/kWh. This means that the turbine was operating with an average yearly heat rate
7.0 percent higher than turbine design heat rate. The actual operating heat rate of 2345 for
turbine No. 3 was the worst heat rate among the 100 MW category turbines at the GRES #2 plant
as can be seen in TABLE 3-4.
Condition Assessment
a)
Unit 3 Problems
Many problems with the turbines and auxiliaries have been identified from discussions with plant
personnel, and from review of documentation received. Some of these problems have resulted in
an increase in unit heat rate, which in turn results in higher operating costs. Some of the problems
increase the probability of unscheduled outages and result in lost generation due to equipment
failure. Some of the problems would result in the need for increased future inspections, major
replacements, and deficiency corrections of internal and external components of the turbine.
Significant problems, which have been identified relative to turbine and auxiliaries, are outlined
below:
Turbine Steam Path/Blading
From the above analysis of performance degradation it can be seen that the efficiency of the steam
path has deteriorated. However, considering the more than double original design life of the
turbine, it has performed fairly reliably. During the past 10 years and especially above 200,000
hours of operation, however, failures of the blading became more prominent. The data received
from the plant on turbine problems and forced outages indicate that the mounting shoulders of the
T-type root attachments of the LP rotor disks and blades operating in the phase transition zone
have been destroyed. It was also reported that after about every 50,000 to 70,000 hours of
operation an unacceptable erosion wear develops on the leading edges of the last stage blades
requiring the replacement of these blades.
The forced outage records between 1985 and 1995 indicate the breakage of all blades at the 26th
stage in 1990. The damage caused by this event required the replacements of the 26th and 27th
stage diaphragms, the 26th stage blading, as well as the shroud of the 20th stage blading. In 1992
two blades of the last stage in the HP section broke, requiring the repair of the blading and
replacement of the 20th stage diaphragm sealing ring.
Turbine Bearings/Vibration
Bearing vibration was reported to be a problem. One of the reasons for this was the problem of
breakage and erosion wear of the blading as described above. Vibration initiated shutdowns of
the turbine were reported in the list of defects for the past 10 year period in 1986, 1987, 1991 and
5909-98A/KARA.DOC/2/8/96
20
1992. The above problems as well as the age of the equipment resulted in excessive wear of the
Babbit metal of bearing surfaces. In many instances the oil seals of the bearings have been
damaged causing oil leakages at various bearings (No. 1, 3, 4 and 6).
Turbine Oil System
The turbine oil system supplies both control oil and lubricating oil to the turbine. The plant has
reported a high sensitivity of the turbine hydraulic regulating system to the cleanliness of the oil.
In 1990 this caused a false protection actuation of shaft driven control components. Oil system
caused failures were also listed in the plant records in 1986 and 1992. The turbine regulating
system and the main oil pump require frequent attention in order to keep the turbine running
satisfactorily.
Turbine Water Induction and Valves
Water induction was not reported to be a problem. The extraction lines for feedwater heaters No.
3 through 8 all have automatic actuated non-return valves as well as isolation valves. No isolation
capability is provided for the No. 1 and 2 LP heaters, and the isolation valves are motor operated
only for the high pressure heater extraction lines. The automatic isolation feature apparently
worked in 1994 when the LP HTR No. 4 was removed from service due to tube leakage.
However, improved water induction features for the unit are still required.
In addition, the plant has reported a large number of problems with many of the valves operating
in the turbine steam/feedwater cycle due to their age. These valves require replacement.
Electric Generator
The outages of the generator listed in plant maintenance and outage records are mainly due to
leakage of hydrogen or the malfunction of the exciter. The seal oil system of the generator failed
in 1989 because of a weld crack in the oil line. In another event, hydrogen circulation was also
interrupted in the same year due to faulty valves. Loss of generator excitation system was also
listed as an item requiring attention. The generator and motor repairs are often made difficult due
to the unavailability of proper insulating materials. The generators of Units 3, 4 and 5 have
served their lives (they accumulated over 2.5 times their original design operating hours) and the
plant has planned their replacement together with the turbines, however, replacements were not
made due to a lack of funds.
b)
Metal Control
Metal control laboratory personnel were interviewed to assess the procedures and equipment the
plant has to monitor metal conditions. The equipment for non-destructive examination (NDE)
and destructive examination (DE) at the plant include:
5909-98A/KARA.DOC/2/8/96
21
UD2-12
Ultrasonic flaw detector
UD-1
Ultrasonic flaw detector
UD-3
Ultrasonic flaw detector
UT-93
Ultrasonic thickness gage
KWARTZ 6
Ultrasonic thickness gage
SLP-1
Universal steeloscope
SLU AL.2.851.047
Universal steeloscope
VRM-12
Hardness tester
VPI-2M6
Hardness meter
X-ray devices and gamma-ray detectors are not used for the detection of flaws in thick walled
pressure parts of the equipment that operate under high pressure. Plant personnel also indicated
they have endoscopes, and magnetic particle (MP) and liquid penetrant (LP) testing capability.
Metallographic Laboratory equipment is placed at the service of Metal and Welding Department
of KARAGANDAENERGO. The plant has no replication type creep detection capability.
Plant personnel indicated that at every 5 years interval, they would test for defects on the inside
and outside surfaces of the turbines. Visual and ultrasonic testing of turbine blades and disks are
performed. The schedule is made for such tests that it is coincident with the major overhaul
periods. No testing is scheduled for the yearly and the intermediate repairs. In addition, they
usually test 50% of the components during the first overhaul and the other 50% during the next
overhaul. It would seem that more frequent testing in a plant with older units is needed and
capability for replication type creep testing would also be needed. However, it was recognized by
the plant staff that the turbine metal fatigue has occurred.
During the last testing of the turbine (Unit 3) which coincided with the last turbine overhaul in
1991 the following defects were found:
Turbine Stop Valve:
Shell crack with dimensions of 55 mm in length, 6 mm
width, 8 mm depth.
Control Valve No. 1:
2 shell cracks: 133 mm long, 55 mm wide, 18 mm deep.
and 55 mm long, 20 mm wide, 6 mm deep.
Control Valve No. 3:
4 shell cracks: 155 mm long, 20 mm wide, 20 mm deep;
95 mm long, 20 mm wide, 20 mm deep; 145 mm long,
25 mm wide, 30 mm deep; 115 mm long, 12 mm wide,
8 mm deep.
Control Valve No. 4:
Shell crack with dimensions of 133 mm length, 55 mm
width, 18 mm depth.
HP Cylinder Nozzles:
Overwear
5909-98A/KARA.DOC/2/8/96
22
HP Cylinder Bolts:
2 bolts replaced.
HP Cylinder Upper:
Shell crack located after control stage with dimensions
of 260 mm length, 54 mm width, and 58 mm depth.
Last Stage 25th, 30th
Blades:
Overwear
During this testing metallographic examination of the turbine metal structure was not performed.
The park resource (currently extended life) of the type K-100-90 turbines is 270,000 hours, with
the following main component lives:
HP Rotor
:
270,000 hrs
HP Cylinder
:
270,000 hrs
Stop and Regulating Valves
:
220,000 hrs
Therefore, the stop and regulating valves should have been replaced some time ago, and that the
remaining life of the rest of the turbine would be about 3 years. While no metal testing data is
available for the inspection of the turbine during previous years, the discovery of additional cracks
can be expected based on experience with similar turbines.
Discussions with plant personnel indicated that the plant's reconstruction plans included the
replacement of the high pressure cylinders, valves, rotors and the electrical generators of Units 3,
4 and 5 steam turbines starting with the year 1993. In fact, further information received from the
plant confirmed that the Unit 3 turbine operates with the testing commission's recommendation to
replace it. It is currently operated under the chief engineer's responsibility.
However, no such replacement has been accomplished so far because of lack of funds. It was also
realized that 99% of the replacement parts are either manufactured in Russia or in the Ukraine and
that the cost of spare parts was prohibitive due to age of the turbine. Furthermore because of the
increase in heating demand in the vicinity of the plant, it is desirable to have future rehabilitation
efforts satisfy the thermal demand, or at least reduce the deficit. Due to these circumstances the
plant procured a new district heating turbine (KT-115/125-130) with a district heat load capability
of 100 Gcal/h. This turbine is currently in storage.
As noted above, there is currently no replication type creep testing capability available at this
plant. As the plant is increasing in age such testing capability would be highly desirable to
monitor potential creep damage of critical components which operate at the end of their park
resource operating hours. Utilization of such testing equipment would enable the plant to better
predict potential failures or to perform predictive maintenance operations. This is particularly
applicable to a plant with many boilers and turbines where such equipment could be often used.
5909-98A/KARA.DOC/2/8/96
23
c)
Spare Parts
Lack of spare parts was reported by plant personnel to be a problem. An adequate supply of
appropriate spare parts, located at the plant, is important to facilitate rapid maintenance when
needed. This is particularly true when failure of a part results in an unscheduled outage, and time
is of the essence in completing the repair to return the unit to service as quickly as possible.
3.3
AUXILIARY PLANT SYSTEMS
It was reported by plant personnel that the reliability of the auxiliary equipment is very low and
adversely affect the turbine availability. These equipment and systems are very old (240-245,000
hours) and have exhausted their useful lives. These systems and equipment include the
components of the regenerative feedwater heating system, and the condenser and various system
valves. The number of unplanned shutdowns on the No. 3 turbine up to 1995 was 179. A large
number of these were in conjunction with the failure of auxiliary equipment. The mean time
interval between failures of the auxiliary equipment ranges between 300 and 800 hours.
a)
Condenser
The most unreliable part of the condensers reported for the Karaganda units is the tubing system.
After about every 100,000 hours of operation the Latuny tube walls are destroyed. The tubes are
exfoliated as the zinc comes out of the Latuny (L-68) compound. The allowable tube plugging is
10%. While the tubing in the condenser of the No. 3 turbine has been replaced before, the
percentage of currently plugged tubes is about 7%, and increasing with further operation. In
addition, the condenser has problems with air inleakage. As can be seen from TABLE 3-4 this
unit has the lowest vacuum and the highest air inleakage among all the GRES-2 units. The most
prominent locations of air ingress are the expansion joints, condensate pump glands, and various
valves connected to the condenser operating under vacuum conditions. However, the condenser
does not seem to require an on-line tube cleaning system.
b)
Feedwater Heaters
The main problem with the feedwater heaters is the deterioration of the tube surfaces. The
turbine water induction protection system successfully isolated LP heater No. 4 in 1994 when
tube breakage caused the water level in the heater to rise. The low pressure heaters utilizes
Latuny (L-68) tubing and the allowable tube plugging is 10%. The high pressure feedwater
heaters (Type PV-250/180) are vertical heaters and have stainless steel tubes. However, due to
their age they have also deteriorated to the point where they will require replacement for
continued reliable operation. Because of this, the high pressure heaters need to be frequently
removed from service. While this problem is applicable to other units of the GRES-2 plant as
well, it is particularly severe at Unit 3. As shown in TABLE 3-4, the temperature of the final
5909-98A/KARA.DOC/2/8/96
24
feedwater leaving the Unit 3 feedwater system was the lowest at 173°C which is 44°C lower than
design temperature.
c)
Pumps and Motors
The feedwater pumps are 5C-10 type with parameters of 270 m³/h and 150 ata driven by ATM-
2000-2 constant speed electric motors. They are of Russian manufacture. The pumps have been
replaced in 1983. They operate with relatively low efficiency (design efficiency was 68%). They
have been operating with low reliability due mainly to the unavailability or high cost of spare
parts.
The condensate pumps are Type 10KSD5x3 horizontal pumps with 175 m³/h, 123 m design
parameters driven by 100 kW electric motors at a speed of 960 rpm. These pumps were
manufactured in 1962 and operate with very low efficiency. Their condition has degraded and
require replacement.
The heater drain pumps also operate with very low reliability, they show the signs of complete
physical deterioration, and need replacement.
The circulating water pumps are type OP3-110-50 with 20,000 m³/h design flow rate and 21 m
W.C. head. They are driven by 1500 kW motors at 585 rpm. These pumps have no lubricating
water problems, and they are protected by stainless steel screens. However, they too are very old
and deteriorated and need replacement.
It was also found that the electric motors driving the various pumps are also in a bad state of
repair. At the time of the Burns and Roe visit, approximately 60 motors were out of service in the
plant. This was due to the unavailability of electric materials to repair the old electrical
components.
d)
Valves
Plant information collected indicated problems with the majority of valves, due to wear since the
unit has accumulated over 243,000 operating hours. Most of the problems were experienced with
the valves operating in the high and medium pressure systems.
3.4
INSTRUMENTS AND CONTROLS
General
The instrumentation at the Karagandinskaya plant is in general based on the philosophy of the
1950's and 1960's. Although we were unable to inspect the plant instrumentation due to a labor
strike, through discussions with plant personnel we were able to ascertain the condition of the
5909-98A/KARA.DOC/2/8/96
25
plant. Since the initial operation in 1962 almost all measuring and indicating devices have been
replaced with newer more modern ones, although the overall philosophy has not changed.
a)
Load Control
Turbine No. 3 uses an electronic governor with a centrifugal speeder gear to vary the speed
setpoint. The boiler pressure controllers are used to vary the fuel flow rate to the boiler. The
pulverized coal is stored in an intermediate hopper and the transport medium from mill to hopper
and from hopper to burner is air from the air heater. There is no oxygen dilution for the transport
air.
Combustion control of the boilers is provided manually by the operators according to established
procedures and are based upon adjustment and testing. Excess air, the main indicator of
performance, is monitored by measuring the oxygen content of the flue gas after the superheater.
Oxygen content is displayed on the boiler control board. Additional indicators of excess air are
air-side resistance of the air heaters and air pressure after the forced draft fan. Vacuum in the
upper section of the furnace is also used as a combustion performance indicator.
The plant operators are preparing a scheme to control air flow automatically using O₂ as a trim.
There is no direct combustion air flow measurement, but they use differential pressure across the
air heater as an indication of air flow.
b)
Air Flow Control
This is purely a manual function carried out by varying the position of the two forced draft fan
radial inlet vanes remotely from the control room. An O₂ indicating system fed from an oxygen
analyzer assists the unit operator in setting the correct combustion air flow rate. Each of the two
50% forced draft fans are electric motor driven, centrifugal type with radial flow. The original
oxygen analyzers are extractive type and consequently slow acting.
c)
Furnace Pressure Control
There is no automatic control of furnace pressure. The position of the two induced draft fans
radial inlet vanes is varied remotely from the control room to adjust the value of the furnace
pressure. Normal vacuum is 3-5 mm Hg.
The two induced draft fan loads must be balanced to prevent choking of the burner flame. The
balancing of the fans is measured by the two induced draft fan ammeters. The two 50% induced
draft fans are electric motor driven, constant speed, centrifugal type and radial flow design.
5909-98A/KARA.DOC/2/8/96
26
d)
Steam Temperature Control
Steam flow is divided into two parallel paths, with steam crossovers at the first and second spray
attemperator stages. There is an attemperation system in the parallel steam paths to the first and
second stage desuperheaters using spray water attemperation valves each with its own dedicated
controller. The spray water source is saturated steam taken from the drum which is then
condensed in a heat exchanger where the cooling medium is the feedwater flow just before entry
to the drum. Apart from the fact that increased attemperation will not impair cycle efficiency, the
system lends itself to good controllability because there is inherent self regulation for changes in
live steam flow. Superheater outlet temperature and a derivative of superheater inlet temperature
are compared to the setpoint to form the control deviation. There is a small amount of valve
leakage, but it is not serious.
e)
Boiler Drum Level Control System
Two feedwater valves control drum level. The first valve is used for filling the drum and for start-
up (burner ignition). Drum level is controlled manually. The second is used during high and full
load operation employing a three element control scheme (feedwater flow, steam flow and drum
level). The system operates properly.
f)
Boiler Interlock and Protection System
A basic interlock system using electrical relays is in existence. Protection is effected via electrical
relays for the following conditions: high and low drum level, high and low steam temperature and
loss of flame. The drum level tripping system sometimes causes false boiler trips, an average of
one or two trips per year.
High superheater pressure (above 107 kg/cm²) causes an automatic runback of coal feeder speed,
which causes the startup of mazut, and opens the drum relief valve. Tripping the boiler will stop
the pulverized coal feeders, close the feedwater valves, close the main steam valve, open the
superheat steam vent and stops the forced draft fans. The induced draft fans continue to run.
g)
Burner Management System
There is no burner management system as such. However the burners are equipped with
photoelectric scanners. The scanner circuits are designed such that a loss of flame for three
seconds will start mazut flow to the burners. If there is still no flame after six seconds, the boiler
will trip.
h)
Boiler Blowdown
Boiler blowdown is accomplished in two ways, continuous and intermittent. Intermittent
blowdown is performed manually under administrative control. However, continuous blowdown
5909-98A/KARA DOC/2/8/96
27
is regulated at 0.3 to 0.5% of steam flow by an electronic controller. The controller monitors
steam flow and blowdown flow and the system works well. These readings are used to position
the blowdown control valve.
i)
Stack Emissions Monitoring
There are no NOx, SO₂, CO, or CO₂ measurements on these units. There is an opacity monitor
installed, but it doesn't work due to heavy particulate loading. Currently NOx, CO₂, and CO are
measured periodically by laboratory analysis.
Since all boilers discharge their flue gases into a single stack, it is difficult to identify gases from
individual boilers. Without the ability to monitor flue gas emissions from each boiler, it is further
impossible for plant maintenance staff to determine which boilers are operating efficiently, and
which may need repair or adjustment.
NOx monitors will be added to the boiler flues as part of the pilot plant upgrade.
j)
Turbine Control
The No. 3 turbine valves are controlled by an electric servo motor system with an electronic
governor. There is one stop valve, four governor valves, and two startup bypass valves. Since
this is not a reheat unit, there are no intercept valves. The intermediate pressure (IP) stage of this
units steam flow is controlled by valves which control steam flow to the district heating system.
k)
Turbine Interlock and Protection System
Interlocks of a basic nature are fitted. Protection applies to the following conditions: excess
rotor axial movement, low steam temperature, low lubricating oil pressure, generator electrical
faults, and loss of vacuum. All of the above protection and interlocks are effected via electrical
relays. Overspeed protection is provided via overspeed rings. The turbine is protected against
water ingress from the feedwater heaters by fast-acting non-return valves and isolating valves in
the bleed steam lines which are activated electrically by electrical sensors on the feedwater
heaters. There is no stress monitoring on the turbine but casing temperatures at various points are
measured and recorded. Turning gear is provided which turns the rotor at 3 to 4 revolutions per
minute.
1)
Turbine Supervisory System
The following supervisory measurements are made on the turbines: thrust bearing position,
eccentricity, vertical and horizontal vibration at all bearings, casing expansion, relative expansion,
bearing oil outlet temperature and turbine speed by a digital electronic system.
5909-98A/KARA.DOC/2/8/96
28
m)
Feedwater Controls
The condenser hotwell level and the levels in the feedheaters are controlled using automatic
regulators. All of the actuators are electrically operated. All heaters and the condenser are
equipped with water level gage glasses. Most extraction points are equipped with a check valve
to prevent water ingress. These valves are equipped with hydraulic accelerators to improve the
valve operating time.
3.5 AIR POLLUTION CONTROL
Emissions of particulates, sulfur dioxide (SO₂) and nitrogen oxides (NOx) and the impact of these
emissions on ambient air quality are of concern to the power plants and the surrounding
communities. At the Karaganda power plant dust collection equipment is provided to remove a
major portion of the fly ash from the flue gas before discharge.
The plant uses Venturi scrubbers to remove the ash from the fluegas for boilers 1 to 6.
Electrostatic precipitators are used on boilers 7 to 15. The current ash collection efficiency of
the scrubbers is reported to be approximately 96.4%. Efficiency of the electrostatic precipitators
is assumed to be similar.
Plant emission rates when firing Ekibastuz coal have been estimated from coal properties, dust
collection efficiency and boiler design features. Estimated emissions, at 40% excess air, are:
Emission
Concentration, mg/Nm³
Ash
2,500
SO₂
2,900
NOx
765
Kazakstani emission limits for new boilers are as follows:
Emission
Concentration, mg/Nm³
Ash
100
SO₂
400
NOₓ
240
It is evident that in order to meet these limits, major investments in Air Pollution Control
Equipment would be required.
Local limits for emission of pollutants into the environment and estimated mass emission limits
have been provided by plant personnel. These are as follows:
5909-98A/KARA.DOC/2/8/96
29
Emission
Limit, g/sec
Estimated, g/sec
Ash
1,808
1,750
SO₂
1,566
1,530
NOx
445
420
These mass emission limits and the reported emissions are apparently based on the annual
emissions permitted by local authorities. It has not been established whether national emission
limits will take precedence.
3.6
DISTRICT HEATING SYSTEM
General
The Karaganda plant provides heat in the form of hot water and steam to three district heating
systems in the vicinity of the plant. The district heating systems serve the town of Topar, the
town of Abai, and the Greenhouses. The demands for these systems and the design heat loads are
as follows.
HEAT LOADS
(Gcal/h)
SYSTEM
DESIGN
ACTUAL
Abai
100
150.5
Topar
125
63.4
Greenhouses
210
172.1
TOTAL
435
386.0
The heat source for the district heating systems is the extraction steam from crossover pipes of
turbines No. 6, 7, and 8 and main steam from the pressure reducing stations. The steam extracted
for district heating applications from all three turbines is cross connected so any turbine can
supply the heat to any of the three districts, that is, Abai, Topar and the Greenhouses. The
amount of heat extracted is as follows:
Source
Amount (Gcal/h)
Turbines No. 6, 7, and 8
300 (100 each)
Pressure Reducing Stations
135
TOTAL
435
The pressure reducing stations take steam from the main steam header and reduce its pressure
(100 ata to approx. 12 to 16 ata) so that the steam can be used in the large district heating heat
5909-98A/KARA.DOC/2/8/96
30
exchangers. These heat exchangers produce the hot water for the three district heating systems.
A small amount of industrial steam is provided to a building materials company from the low
pressure steam supply downstream of the pressure reducing stations. The industrial steam is
delivered at a pressure and temperature of 6 ata and 210 to 250°C respectively. The industrial
steam flow rate is 10 t/h. The condensate is not returned to the power plant from the building
material company.
The Topar System
Topar is a small village located very close (approximately 3 km) to the power plant. This system
has the smallest heat load of the three systems at 63.4 Gcal/h. The system has two pumping
stations which distribute the hot water to the village. The village requires a flow rate of 1100
m³/h of hot water from the power plant. The pumps at the pumping station are motor driven and
are controlled by throttling the flow. These pumps are constant speed pumps.
The main transmission piping to the Topar pumping stations is 530 mm in diameter and has a wall
thickness of 8 mm. The distribution piping from the pumping stations varies from 426 to 150 mm
in diameter. Topar district heating piping is in relatively good shape. The lines have an operating
pressure of 7.0 ata. The pressure drop to the last customer is estimated to be 2.5 ata + 0.1 ata.
The system operates under constant flow/variable temperature conditions. The heating schedule
for the system is shown in TABLE 3-6.
There are no heat exchangers used in the individual houses in the Topar system. It is a direct
(open) system. The hot water from the pumping stations flows to the houses and circulates in the
radiators to provide heat. This water is also used to provide domestic hot water needs. The hot
utilization water is taken directly from the district heating system. Thus, the hot tap water is
identical with the water in the district heating pipes.
Makeup water for the system is taken from the lake located next to the power plant. This water is
treated only with softeners to remove the hardness from the water. No chemicals are added to the
water because it is also used for domestic purposes (for kitchens and bathrooms).
The present supply strategy is based on the constant flow principle where the flow in the district
heating system is close to constant and the heat supply is adjusted by changing the supply
temperature. If heat is needed in the network the supply temperature is increased
correspondingly. Due to the constant flow system, the consumers will experience the increased
heat supply with a certain time lag depending on the velocity of the DH-water and the distance
from the heat supply source. The time lag will typically last from a few minutes for the nearest
consumers to a number of hours for the most distant consumers. In some cases, the heat will
reach the most distant consumers after the heat demand has actually ceased meaning an excess
temperature at the consumers. As the consumers are normally left with poor heat regulation
possibilities, this means the only way to regulate the indoor temperature will be by opening
windows leading to a high energy loss.
5909-98A/KARA.DOC/2/8/96
31
The circulation of the water in the district heating system is done by constant flow pumps located
at the power plant. The system is designed with a number of larger capacity pumps used for
winter and a number of relatively smaller capacity pumps used during the summer for the hot
water supply. A number of pumps are also located in the district at the two pumping stations as
booster pumps or to overcome the large differences in ground level between the main network
and certain consumer groups. The network is characterized by a large number of ring connections
which means a relatively high supply security.
The distribution network is composed of many individual networks each connected directly to the
main network, "Connection points". Buildings and industrial consumers are connected to the
distribution network through the so called "Thermal points". The dwellings are normally
connected through a "hydro elevator" which is a hydraulically open connection. The industrial
consumers are normally connected through heat exchangers, which isolate the internal distribution
system hydraulically from the district heating system.
The district heating hot water transmission piping system described above comes under the
jurisdiction of the district heating company. The district heating company interfaces with both the
power plant and the local distribution companies whose function also includes local servicing
inside the buildings and the collection of the tariff for the heat and hot water energy consumption.
The accounting method for heat and hot water is such that only the few larger customers pay
according to the actual heat they use. These customers have flow meters in their supply lines as
well as thermometers in supply and return lines. The heat consumption is determined from the
product of the flow rate and the supply and return temperature differential. The smaller
customers pay for heat based on the floor area of their homes. They pay for domestic hot water
based on the number of persons living in the household.
5909-98A/KARA.DOC/2/8/96
32
TABLE 3-6
TOPAR SYSTEM HEATING SCHEDULE
District Heating Water °C
Without Wind Chill
With Wind Chill
Outside Air
SUPPLY
RETURN
Y-1.05
Y-1.10
Y-1.0
Temp. °C
8
60
47.7
43.1
44.3
45.4
7
60
47.3
45.1
45.4
47.7
6
60
4730
47.2
48.6
50.0
5
60
46.6
49.2
50.7
52.2
4
60
46.2
51.2
52.8
54.3
3
60
45.9
53.2
54.8
56.5
2
60
45.5
55.1
56.9
58.6
1
60
45.2
57.0
58.9
60.8
0
60
44.8
58.9
60.9
62.8
-1
60
44.5
60.8
62.9
64.9
-2
60
44.2
62.7
64.9
67.0
-3
62.4
45.6
64.6
66.8
69.0
-4
64.1
46.5
66.4
63.7
71.1
-5
65.9
47.5
68.3
70.7
73.1
-6
67.6
4834
70.1
72.6
75.1
-7
69.4
49.4
71.9
74.5
77.1
-8
71.1
50.3
73.7
76.4
79.0
-9
72.8
51.2
75.5
78.3
81.0
-10
74.5
52.1
77.3
80.1
82.9
-11
76.2
53.0
79.1
82.0
84.9
-12
77.8
53.8
80.8
83.3
86.8
-13
79.5
54.7
82.6
85.7
88.7
-14
81.2
55.6
84.3
87.5
90.7
-15
82.8
56.4
86.1
89.3
92.6
-16
84.5
57.3
87.8
91.1
94.5
-17
86.1
58.1
89.5
92.9
96.3
-18
87.8
59.0
91.2
94.7
90.2
-19
89.4
59.8
93.0
96.5
100.1
-20
91.0
60.6
94.7
98.3
102.0
-21
92.6
61.4
96.4
100.1
103.8
-22
94.2
62.2
98.0
101.9
105.7
-23
95.8
63.0
99.7
103.6
107.5
-24
97.4
63.8
101.4
105.4
109.3
-25
99.0
64.6
103.1
107.1
110.0
-26
100.6
65.4
104.7
108.9
110.0
-27
102.2
66.2
106.4
110.0
110.0
-28
103.8
67.0
103.0
110.0
110.0
-29
105.3
67.7
109.7
110.0
110.0
-30
106.9
68.5
110.0
110.0
110.0
-31
108.4
69.2
110.0
110.0
110.0
-32
110.0
70.0
110.0
110.0
110.0
5909-98A/KARADOC/2/8/96
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The Abai System
The town of Abai is located approximately 20 km from the plant. The Abai hotwater district
heating system has a total of 20,145 meters of double pipes (hot water supply and return
pipes). The main transmission lines vary in diameter from 1000 mm to 150 mm. The
distribution piping has smaller diameters. The system hotwater flow rate is 2400 m³/h.
Makeup to the system is provided in the same manner as the Topar system. The makeup for
the Abai system is estimated to be 60 t/h. The system has three pumping stations with 3
pumps each. Two different model pumps are used in these stations. They have capacities of
1260 and 2500 m³/h to satisfy various heat load conditions. Currently the system has a
demand of 150.5 Gcal/h. The Abai system heating schedule is shown in TABLE 3-7.
The Topar district heating system is an open system whereas the Abai district heating system is
a closed system. In a closed system the district heating hot water is used in radiators for space
heating only. This water is returned to the plant after it has circulated through the radiators.
Domestic hot water needs for kitchens and bathrooms are provided by individual hot water
boilers located at the houses. However, because of lack of fuel and money, the individual
hotwater boilers at the houses are not utilized nowadays, and people steal hotwater for
domestic use from the Abai district heating system.
The transmission piping network is characterized by a number of ring connections, which cross
each other at various "Node points". This allows a relatively high security of heat supply. In
addition there are other node points or connecting points at which the piping systems of the
various distribution systems are connected to the main transmission headers. However, there
is a lack of instrumentation and control of flow and isolation capability at these node points,
and there is a very minimal number of instrumentation and automatic control at the pumphouse
and the dispatch center. Those that are available are quite old, either needing repair or
recalibration. Without instruments which function properly to monitor and record such
essential variables as flow rate, temperature, and pressure, it is difficult to accurately
determine balance measurements and conduct effective energy efficient system operation.
The Abai district heating system is operated in the same manner as the Topar System, that is,
on the constant flow principle where the hotwater flow in the system is close to constant and
the heat supply is adjusted by changing the supply temperature. It has the same problems as
described for the Topar system as far as the heat regulation and the time lag between heat
demand and supply is concerned. The thermal energy billing methods and responsibility for
collection of thermal energy tariff is similar to those of the Topar system.
5909-98A/KARADOC/2/8/96
34
TABLE 3-7
ABAI SYSTEM HEATING SCHEDULE
District Heating Water Temp. °C
Outside
Relative Heat
Before Heat
With Wind
Inside Air
Temp. °C
Consumption
Supply
Return
Exchanger
Chill
Temp. °C
8
0.36
70.0
51.9
61.0
70.0
26.1
7
0.37
70.0
51.6
60.8
70.0
25.4
6
0.38
70.0
51.3
60.6
70.0
24.7
5
0.38
70.0
51.0
60.5
70.0
24.0
4
0.39
70.0
50.6
60.3
70.0
23.4
3
0.39
70.0
50.3
60.2
70.0
22.7
2
0.40
70.0
50.0
60.0
70.0
22.0
1
0.41
70.0
49.7
59.3
70.0
21.3
0
0.41
70.0
49.3
59.7
70.0
20.7
-1
0.42
70.0
49.0
59.5
70.0
20.0
-2
0.43
70.0
48.6
59.3
70.0
19.4
-3
0.43
70.0
48.3
59.2
70.0
18.7
-4
0.44
70.0
48.0
59.0
72.6
18.0
-5
0.46
72.1
49.1
60.6
74.8
18.0
-6
0.48
74.1
50.1
62.1
76.9
18.0
-7
0.50
76.1
51.1
63.6
79.0
18.0
-8
0.52
78.2
52.2
65.2
81.2
18.0
-9
0.54
80.2
53.2
66.7
83.3
18.0
-10
0.56
82.2
54.2
68.2
85.4
18.0
-11
0.58
84.2
55.2
69.7
87.5
18.0
-12
0.60
86.2
56.2
71.2
89.6
18.0
-13
0.62
88.2
57.2
72.7
91.7
18.0
-14
0.64
90.1
58.1
74.1
93.7
18.0
-15
0.66
92.1
59.1
75.6
95.8
18.0
-16
0.68
94.1
60.1
77.1
97.9
18.0
-17
0.70
96.0
61.0
78.5
99.9
18.0
-18
0.72
98.0
62.0
80.0
102.0
18.0
-19
0.74
99.9
62.9
81.4
102.1
18.0
-20
0.75
101.1
63.3
82.2
101.1
17.7
-21
0.75
100.1
62.3
81.2
100.1
16.7
-22
0.75
99.1
61.3
80.2
99.1
15.7
-23
0.75
98.1
60.3
79.2
98.1
14.7
-24
0.75
97.1
59.3
78.2
97.1
13.7
-25
0.75
96.1
58.3
77.2
96.1
12.7
-26
0.75
95.1
57.3
76.2
95.1
11.7
-27
0.75
94.1
56.3
75.2
94.1
10.7
-28
0.75
93.1
55.3
74.2
93.1
9.7
-29
0.75
92.1
54.3
73.2
92.1
8.7
-30
0.75
91.1
53.3
72.2
91.1
7.7
-31
0.75
90.1
52.3
71.2
90.1
6.7
-32
0.75
89.1
51.3
70.2
89.1
5.7
5909-98A/KARA.DOC/2/8/96
35
The Greenhouses
The third system that the Karaganda plant serves is the Greenhouses. The greenhouses are
located approximately 3.4 km from the plant. There are six separate greenhouses in this
system. This district heating system is the largest one served by the plant with a thermal
demand of 171 Gcal/h. The heating schedule for the greenhouses is shown in TABLE 3-8.
The transmission lines that travel to the greenhouses are divided into two groups. The first
group serves greenhouses No. 1 to 5. It consists of 3 lines, 2 supply and 1 return line. The
supply lines have diameters of 500 mm, while the return line is 700 mm. The second group
supplies greenhouse No. 6 only. It has one supply and one return line. Both lines have 700
mm diameters. The first group of transmission lines were constructed from 1977 through
1979, while the second group was constructed during 1982 through 1984 time period. All the
piping is above ground.
The greenhouses are used to grow a wide variety of fruits and vegetables all year around. The
greenhouses have a total floor area of 220,000 square meters. The system requires a
maximum of 3000 m³/hr hot water. The hotwater flow is changed (adjusted) at the power
plant when requested by the greenhouses. Makeup water is needed at an estimated rate of 15
to 45 m³/h.
5909-98A/KARA.DOC/2/8/96
36
TABLE 3-8
GREENHOUSE SYSTEM HEATING SCHEDULE
District Heating Water Temp. °C
Outside Air Temp. °C
Relative Heat Consumption
Supply
Return
With Wind Chill
10
.19
56.5
37.9
58.1
9
.21
59.6
39.1
61.2
8
.23
62.6
40.3
64.5
7
.25
65.5
41.4
67.4
6
.27
68.4
42.4
70.4
5
.29
71.3
43.4
73.5
4
.31
74.2
44.5
76.5
3
.33
77.0
45.4
79.4
2
.35
79.8
46.4
82.5
1
.37
82.6
47.3
85.2
0
.38
65.5
46.3
67.4
-1
.40
67.4
47.2
69.3
-2
.42
69.3
48.1
71.3
-3
.44
71.1
49.0
73.2
-4
.46
72.9
49.8
75.1
-5
.48
74.7
50.7
77.0
-6
.50
76.5
51.5
78.8
-7
.52
78.3
52.3
80.7
-8
.54
80.1
53.1
82.5
-9
.56
81.8
53.7
84.3
-10
.58
83.6
54.7
86.2
-11
.60
85.3
55.5
88.0
-12
.62
87.0
56.3
89.8
-13
.63
88.7
57.0
91.6
-14
.65
90.5
57.8
93.3
-15
.67
92.2
58.5
95.1
-16
.69
93.9
59.2
96.9
-17
.71
95.5
60.0
98.6
-18
.73
97.2
60.7
100.4
-19
.75
98.9
61.4
102.1
-20
.77
100.5
62.1
103.9
-21
.79
102.2
62.8
105.0
-22
.81
103.9
63.5
105.5
-23
.83
105.0
63.7
105.0
-24
.85
105.0
62.7
105.0
-25
.87
105.0
65.8
105.0
-26
.88
105.0
64.9
105.0
-27
.90
105.0
64.0
105.0
-28
.92
105.0
63.2
105.0
-29
.94
105.0
62.3
105.0
-30
.96
105.0
61.4
105.0
-31
.98
105.0
60.6
105.0
-32
1.00
105.0
59.7
105.0
5909-98A/KARA.DOC/2/8/96
37
Condition Assessment
All three district heating systems have been in operation for about 20 to 30 years. The general
condition of the district heating piping for the Abai and Greenhouse systems is relatively poor.
The piping is subjected to corrosion from the outside due to high humidity in the ducts and
wet insulation. Water leakage from holes in the piping system which are not discovered and
repaired accelerate the outside corrosion. Rain and sewage water also finds its way through
the cracks in the concrete enclosure add to the corrosion process. The district heating pipes
also corrode from the inside due to lack of water treatment, that is, due to dissolved oxygen,
chlorides, and high conductivity of the water. All of the above result in accelerated rate of
corrosion of the piping system.
The portion of the piping which is routed above ground has metal covers (jacket, either
Aluminum or Zinc). The underground piping segments which are usually routed in concrete
tunnels, have no metal jacket and the insulation is held in place by wires. The type of
insulation used is either "diatom" or "mionvata" type. The diatom type system is of Russian
manufacturer, and consist of brick shaped insulating blocks plus asbestos material. The
"minovata" insulation is similar to mineral wool based insulation system and is held in place
with wires.
For the aboveground piping, the age and the exposure of the joints of the metal jacketing often
results in the ingress of rainwater and moisture to the carrier pipe. This causes both external
corrosion of the bottom of the carrier pipe and sagging of the insulation within the jacketing.
For the underground pipes, the occasional partial flooding of the tunnels causes the bottom
portion of the pipes to be submerged. This also leads to the external corrosion of the carrier
pipe. The district heating company would like to have the piping replaced with the
preinsulated, bonded pipes used in most European countries.
Over the years, many of the piping sections have been replaced and repaired. In recent years,
this program has slowed due to budget problems. Thus, many of the above and below ground
piping network are in need of repair or replacement. Replacement of these piping sections
with new preinsulated pipe would reduce both temperature and water losses.
The heating systems in the houses are only operated during the heating season (from October 15
to April 15) with a constant water flow. The Topar system return line supplies the domestic
waste needs when heating system is shutdown during the summer months.
Heat Losses
The heat losses from all three district heating system can be divided into:
Heat losses from the underground network including pipes, valves, chambers.
5909-98A/KARA.DOC/2/8/96
38
-
Heat losses from the aboveground network including pipes, valves, chambers.
-
Heat losses from other installations i.e., substations, pump stations etc.
Dispatcher
Authority resides within the distribution system to determine the amount of heat that the district
heating system requires at any one time. A central dispatcher monitors the system and the outside
air temperature. The dispatcher determines the outdoor temperature, and then based on a
temperature chart, determines what the district heat supply temperature should be. The district
heating system is designed to supply 150°C, but in reality only supplies a maximum of about
110°C. The dispatcher notifies the power plant operators what temperature they are to produce,
and they are required to follow those directions.
District Heating System Instruments and Controls
A minimal number of instruments and automatic controls are available in the district heating
systems. Those that are available are quite old, either needing repair or recalibration. Without
instruments which function properly to monitor and record such essential variables as flow rate,
temperature, and pressure, it is difficult to accurately determine balance measurements and
conduct effective energy efficient system operation.
Control Systems
The main problem within the end-users is the lack of temperature control. Few buildings have any
control device, and most are overheated for a significant portion of each year. The piping design
used in each building is standard, with a venture device blending water to provide a reduced water
temperature to the building. Since this device is incapable of changing with the season or outdoor
temperature, it is dependent on the entering supply temperature to provide the correct amount of
heat. In theory when water is blended or mixed, the heat to the building will be adequate but not
excessive. But this system is not very effective, and many buildings residents open their windows
while the heating system is operating. Opening windows serves as a control device, but obviously
is not very effective, and causes additional heat to be expended.
Several control techniques can be used to improve or replace this system and provide proper
control to the building. The best method involves adding temperature control to each terminal
heating device or to each heated room. This provides good control, and allows each room to be
controlled to a specific setpoint. As the outdoor temperature changes or the effects of the sun
vary throughout the day, the control device will adjust the water temperature to maintain the
room temperature.
5909-98A/KARA.DOC/2/8/96
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Other Problems
Modifications to the heat generation methods used by the plant are also needed. Currently
most of the heat is supplied by turbines No. 6, 7 and 8. Any additional heat that is required is
taken from the main steam header. Taking steam from this location may reduce the electric
generating capacity of the plant. The plant would like to install a new turbine with a district
heating (nominal) capacity of 80 Gcal/h. With this new turbine, the plant would not need to
use steam from the main steam header.
In the Abai system, the water makeup rate varies between 80 and 165 t/h. This high makeup
rate is due to the leaking of various supply and return lines due to age. The other major factor
is the use of radiator water for domestic needs. As was stated previously, the district heating
water from the power plant is used for space heating requirements only. Per design all
domestic hot water needs are satisfied by individual hot water boilers for Abai system. Due to
the slowing of the Kazak economy, most people can not afford to pay for fuel to use in their
hot water boilers. They steal hot water out of the radiator for domestic use.
Other items in need of repair are the pumps in the pumping stations. Many of these pumps are
very old and are in need of repairs. Due to their old age, no spare parts are available. Thus,
the best course of action would be to replace some of these pumps with new ones.
5909-98A/KARADOC/2/8/96
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4.0
REHABILITATION RECOMMENDATIONS
4.1
STEAM BOILERS
The following items are recommended for rehabilitation of boilers 7, 10, and 13 at the Karaganda
GRES #2:
Condition assessment by nondestructive/destructive examination (NDE/DE) of the
thickwalled pressure parts of all three (3) boilers for evidence of low-cycle fatigue
and/or creep type failures. To be examined are the main and surge (small diameter)
steam/water drums, final superheater inlet and outlet headers, steam attemperators and
1st stage economizer inlet headers.
Condition assessment by NDE/DE of the thinwalled boiler pressure parts of all three
(3) boilers for evidence of low cycle fatigue and/or creep type failures, tubewall
thinning by erosion, water and/or fire side corrosion, etc. To be examined are the
furnace tubewalls, radiant roof superheater tubes and pendant convective superheater
tubebanks and economizer stages tubebanks. We also recommend investigating the
feasibility of replacing the existing staggered bare tube arrangement economizer banks
with extended surface (finned) in-line arrangement tubebanks.
Repair or replacement of thick and thinwalled boiler pressure parts as per above
assessments. According to plant personnel, up to 60~70% of furnace tubing may have
to be replaced. In addition, the pendant convective final superheater tubebanks and
possibly the inlet and outlet headers have creep type failures. The economizer
horizontal convective tubebanks have severe erosion type damage and failures. Also
the 1st stage economizer inlet header may have thermal shock type ligament cracks.
Repair or replacement of boiler setting consisting of furnace tubewalls refractory,
insulation, casing, drum enclosures insulation, horizontal and vertical convective
passes refractory brick lining, casing, and tubular airheater stages metal casing.
Refurbishment as required of the tube penetration seals in the horizontal and vertical
convective fluegas passes.
Repair or replacement of the tubular airheater tubebanks. Both airheater stages have
severe tube erosion damage and the 1st stage tubebanks cold end has acid dew point
low temperature corrosion damage was well.
Repair or replacement of fluegas ducting from tubular AH exit to the ESP, from the
ESP to ID fans, from ID fans to stack, including damper refurbishing and replacement
of metallic expansion joints with elastomer fabric type joints, and repair of hangers etc.
5909-98A/KARA.DOC/2/8/96
41
Condition assessment of the draft plant fans, including site performance tests. Repair
or replacement of the severely erosion damaged induced draft (ID) fan housings and
impellers.
Repair or replace the erosion damaged milling circuitry components, e.g. milling
circuit and burner PA/PC conduits, classifiers, separating cyclones, exhauster fan
housings, and impellers. Ball mills refurbishment including trunnion seals, sealing air
fans, trunnion bearings, drive system components, mill liners, lubrication system and
electric motor drives.
Retrofit of a low NOₓ firing system which will include the dismantling and removal of
the existing two (2) levels of four secondary air and coal injection nozzles. Installation
of a low NOx concentric firing system (LNCFS) with either close coupled or separate
overfire air (CCOFA or SOFA). A retrofit system is preferred that will not necessitate
modifications to the injection nozzle furnace tube openings.
Repair or replacement of the particulate emission control equipment (ESPs) of all
three boilers.
Supplement and/or modernize the burner management and instruments and controls
systems of all three boilers.
Additional (non-boiler island) item:
Repair or replacement of the boiler feed pumps of all three boilers.
4.2
STEAM TURBINE GENERATOR
Based on the assessment of the current performance and condition of the No. 3 steam turbine the
following major replacements and modifications are recommended:
a)
Steam Turbine
The No. 3 turbine has experienced various problems, which are continuous in nature, and which
are likely to result in additional deterioration of efficiency, increased frequency of unscheduled
outages, and increased time out of service for inspection and repair. Accordingly, it is
recommended that a plan be made to replace the main turbine, complete with ancillary systems
and components, from the main steam stop valve inlet to exhaust hood and connection to main
condenser, including instrumentation and controls, control valves, lube oil system, steam seal
system, extraction steam system, heater drain system, and interconnecting piping.
5909-98A/KARADOC/2/8/96
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The replacement unit for the No. 3 turbine would be the new KT-115/125-130 machine that the
plant currently has in storage. This type of machine was manufactured by the Leningrad
Machinery Company (LMZ) and was developed for the replacement of 25-100 MW units when
rehabilitating older power plants.
This turbine is furnished with two controlled heat extractions for district heating and for industrial
steam supply. The unit comes with a simplified regenerative feedwater heating circuit which
allows the unit to be installed in existing power stations. This cycle is simple compared to the
other models of the same designation because one low pressure heater and one high pressure
heater are removed from the regenerative feedwater heating circuit.
This simplified steam turbine can be furnished in three different configurations (Type 1, 2 or 3)
depending on the number and length of the last stage blades. The turbine in storage at the
Karaganda Power Plant is a Type 2 and has 650 mm long last stage blades. This turbine is very
effective in the heating regimes of operation, where good economics are possible because of small
losses at the low pressure stages during maximum heat load. In addition, this unit has a condenser
with built-in tube bundles which can be used to heat district heating water returning from the
district heating network. The turbine can also operate with limited steam extraction flow to the
high pressure heaters. This allows the increase of electrical and heating loads.
The KT-115/125-130 turbine's control system is electro-hydraulic. Compared to the old hydraulic
systems the new system provides a wider range of automatic controls and increases the precision
of maintenance of the controlled parameters. The turbine is equipped with the protection systems
and signal systems, and also with the remote control systems which are used in turbine operation.
The turbine KT-115/125-130 has technical and economical parameters on the same level as other
modern heating turbines.
It should be noted that as the model number indicates this turbine was designed to operate with
initial steam pressure of 130 kg/cm². The pressure in the main steam headers in the Karaganda
plant, however, is only 90 kg/cm². Nevertheless the turbine can operate with main steam pressure
of 90 kg/cm2 and main steam temperatures between 500 and 535°C, but the steam flow and power
output will be reduced compared to the original design.
Under these main steam conditions the turbine will have a nominal electric output of 90 MW and
a total heat output of about 155 Gcal/h of which about 100 Gcal/h can be used to satisfy district
heating hot water loads, and the rest can be extracted at about 10 ata as industrial steam supply if
needed. Under such conditions the turbine will require about 400 t/h main steam flow. In
addition, the unit can also be operated in the pure condensing mode of operation. Under the pure
condensing mode with a main steam flow rate of 400 t/h the turbine output will be 105 MW.
Installation of this turbine not only increases the operating life of the plant by about 25 years, but
more importantly it will reduce the approximately 86 Gcal/h of current deficit in the district heat
supply. In addition, both the electric output capability and the operating efficiency of the No. 3
5909-98A/KARA.DOC/2/8/96
43
unit will be improved. The information collected from the plant indicates that when this turbine is
operated with the district heating load, the average yearly guaranteed turbine heat consumption
will be 1990 kcal/kWh. Therefore based on the current average 1994 actual annual average heat
rate of the existing No. 3 unit the improvement is 2345-1990 = 355 kcal/kWh. The turbine
electric output capability would be increased by 5%.
The above improvements are summarized in the table below:
Current
New
Improvement
Unit
%
Electric Output,
100
105
5
5.0
(Condensing Mode) MW
Heat Consumption
2345
1990
355
15.1
(Average annual)
kcal/kWh
Therefore, the new unit would operate with an overall turbine cycle efficiency of 43.2%.
b)
Generator
In order to ensure the trouble-free operation of the new turbine, the generator, exciter, and the
seal oil system should be replaced together with the steam turbine. The Unit 3 generator is 33
years old and was already planned to be replaced in 1993.
c)
NDE Equipment
At the present time no replication type creep monitoring equipment exist at the plant. It is
recommended that such equipment as well as additional boroscopes be purchased as soon as
possible in order to better be able to predict metal degradation and to detect minor cracks in thick
walled pressure parts of the 7 turbines (and 16 boilers). This equipment should be also used
between now and the time of the actual replacement of the Unit 3 turbine.
d)
Spare Parts
It is recommended that based on the recommendations of cognizant plant engineering
management, the stipulation of the manufacturers of major plant equipment, and other
considerations, that an adequate inventory of spare parts for the upgraded (and existing)
equipment be established.
5909-98A/KARA.DOC/2/8/96
44
4.3 AUXILIARY PLANT SYSTEM
Based on the assessment of the current condition of the plant auxiliary equipment the following
additional modifications and replacements are recommended:
a)
Condenser
Replace the entire condenser with optimized conditions to match the new heat duty required by
the new turbine exhaust.
In addition, institute a formal air inleakage detection program to systematically detect and
eliminate air ingress into the vacuum space of (all) condenser(s).
b)
Feedwater Heaters
All existing feedwater heaters should be removed and replaced as required by the new thermal
cycle of the steam turbine.
c)
Piping and Valves
All extraction and heater drain system piping and valves shall be replaced with those required by
the thermal cycle of the steam turbine.
In addition, the main steam piping and isolation valves should be replaced from the boiler header
to the new steam turbine.
The above replacements will eliminate the problems with the high and intermediate pressure
valves. In addition, the extraction and feedwater heater drain systems shall have valves and
protection logic to guard against turbine water induction. This shall be applicable for all
feedwater heaters whether they are installed outside or inside the condenser neck and whether
they are vertical or horizontal.
d)
Pumps and Motors
The following pumps and motors should be replaced with ones optimized for the flows of the new
simplified thermal cycle and with better efficiencies than those of the original equipment:
Boiler feed pumps
Condensate pumps
Heater drain pumps
5909-98A/KARADOC/2/8/96
45
Circulating water pumps
e)
District Heat Supply Components
In addition to the component replacements described in the above paragraphs, the new thermal
cycle of the KT-115/125-130 turbine will require the installation of the following major
components:
Two - 50% capacity district heating heat exchangers
Three - 50% capacity district heating water circulating pumps
District heating heat exchanger drain pumps.
Interconnecting piping and valves between the turbine and the district heating condensers.
Interconnecting piping and valves between district heating condensers and condensate
system components.
Interconnecting (hot water) piping and valves between the new district heating heat
exchangers and the existing district heating water supply system piping.
Instrumentation and controls for heat supply.
4.4 INSTRUMENTATION AND CONTROLS
The recommended action involves the repair and replacement of the instrumentation and controls,
as necessary, plus the implementation of additional I&C equipment.
The following plant instrumentation and control improvements are recommended for the boiler
and turbine systems.
Vibration monitoring equipment, both portable and stationary to measure the vibration at
the bearings of the turbine-generator.
Coal flow measurement for the boiler to determine improvements in efficiency as reflected
in decreased fuel consumption.
Oxygen content measurement in the feedwater for improved control of feedwater
chemistry.
5909-98A/KARA.DOC/2/8/96
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NOx monitoring equipment to determine the effectiveness of NOx reduction initiatives in
the boilers.
SO₂ monitoring equipment to determine the effectiveness of SO₂ reduction initiatives.
Phosphate monitoring equipment in the feedwater for improved control of feedwater
chemistry.
PH monitoring of feedwater for improved feedwater chemistry control.
Flame temperature monitoring to assist in adjusting boiler parameters for low NO burning
and to decrease the level of unburned carbon in the ash.
High temperature O₂ monitors to adjust the boiler for optimum efficiency.
Instruments for measuring carbon content in ash (on-line) to determine the burners
performance.
Primary air flow monitors to balance flow to the mills.
Secondary air flow monitors to balance flow to the burners.
CO monitoring equipment to adjust the boilers for optimum efficiency.
CO₂ monitoring equipment to determine excess air testing of the burners.
Opacity monitoring equipment for flue gas after the boiler and ID fans to determine the
effectiveness of the particulate control equipment.
Moisture monitoring equipment to determine quantity of water in the flue gas, in order to
perform combustion calculations.
Flue gas flow monitoring to determine mass release rates of pollutants from the boiler.
Portable combustion analyzer with peripherals to adjust the boiler parameters.
Heat spy to quickly determine heat leakage points from the boiler and turbine and
determine "Hot Spots" in electrical equipment.
Oil in water monitoring to detect oil leakage from the oil coolers to the circulating water
system.
5909-98A/KARADOC/2/8/96
47
Salt monitoring to determine efficiency of boiler blowdown system.
This list was developed during the condition assessment and is considered necessary for
rehabilitation and modernization. Installation of this instrumentation will extend the plant life and
yield improvement in reliability and availability and reduce maintenance costs.
4.5
AIR POLLUTION CONTROL
Present levels of plant emissions have been estimated at:
NOx
765 mg/Nm³
SO₂
2,900 mg/Nm³
Ash
2,500 mg/Nm³ with 96.4% efficient dust collection
Pollution control equipment options for reduction in these emissions are described below:
The Karaganda Power Plant was engineered and constructed with due consideration of the
environmental laws and regulations in place at the time of construction. Accordingly, particulate
removal systems were installed on the boilers.
To achieve the Kazakstani emission limits (new boilers) described in Section 3.5 would require
the following emission control efficiencies.
Emission
Limit, mg/Nm³
Efficiency, %
NO,
240
68.6
SO₂
400
86.2
Ash
100
99.85
NO, emissions can be reduced to about 400 mg/Nm³ by modification to the combustion
system. Application of a low NOx firing system (LNCFS) referred to in paragraph 4.1 is
recommended.
Reducing NOₓ emissions to 240 mg/Nm³ (the limit suggested for new boilers) requires post
combustion NOx controls. A 40% reduction in NOx emissions (from 400 mg/Nm³) could be
achieved by ammonia or urea injection into the furnace. This technology, although low in
capital investment requirements, adds significantly to the system operating costs and is not
recommended at this time.
Reduction in SO₂ emissions would require post combustion controls. Reducing emissions
from the uncontrolled level to the suggested level of 400 mg/Nm³ requires the application of
flue gas desulfurization technology. Lime based semi-dry scrubbing is the most likely
5909-98A/KARA.DOC/2/8/96
48
technology to achieve this emission reduction. Because of the low sulfur content of the
Ekibastuz coal, flue desulfurization is not recommended at this time.
Reduction in particulate (ash) emissions to achieve the suggested limit of 100 mg/Nm3 would
require dust collection equipment with a collection efficiency of 99.85%. This collection can
be achieved utilizing a high efficiency electrostatic precipitation or a fabric filter system.
Replacement of the current ESP's with modern, high efficiency units is recommended.
Final recommendations for emission control equipment will depend primarily on the specific
regulatory limits imposed by the regulatory agencies. These limits, and the optimum control
technologies are the subject of a USAID funded investigation, Kazakstan Regional Environmental
Improvement Study, presently in progress. Results of this program will be available in late 1996.
However, for this plant rehabilitation cost estimate, the cost of replacement of electrostatic
precipitators have been included to meet the stringent government standards for particulate
removal. NOx control equipment recommended will achieve a substantial reduction in emissions.
4.6
DISTRICT HEATING SYSTEM
As described in Section 3.6, the Abai and Greenhouse hotwater district heating systems supplied
by the Karaganda combined heat and power plant are suffering from internal and external piping
corrosion, extensive water and heat losses due to leakages, poor and damaged insulation, and a
lack of preventive maintenance. All three systems also suffers from inflexible load dispatching due
to constant flow operation and lack of metering at the end users. The end users have no means to
regulate the supply of heat other than opening of the windows which waste the thermal energy.
For all three district heating systems variable speed pump drives should be installed with
automatic control (SCADA) system. In addition, the makeup water plant capacity for all three
district heating systems should be increased after a detailed study.
The following additional recommendations are made for the three (Topar, Abai and Greenhouse)
hotwater district heating systems.
Topar
Install heat control and measuring devices (thermostats, control valves and energy
meters) at the customers locations.
Abai
Replace 3 DH water pumps in pumping station No. 2 because they are very old and need
frequent maintenance.
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Repair and/or replace deteriorated water piping. A thorough piping inspection should be
performed to determine which piping should be replaced. However, we have assumed
that 20% of the piping will need to be replaced in preparing our cost estimates.
Install flow, temperature, and pressure instrumentation at the various pumping stations.
Install heat control and measuring devices (energy meters, thermostats and control valves)
at the customer locations (apartment houses).
Greenhouses
Replace DH circulation pumps with pumps that have the proper characteristics for the
greenhouses.
Install various heat control and measuring devices (energy meters).
Install water flow regulators for the individual units in each greenhouse (3 way valves)
Repair and/or replace approximately 6.6 km of 500 mm diameter hot water supply lines
which feeds Greenhouses 1 through 5.
A new energy control system should be installed to control the temperature of air inside
the greenhouses. This system (SCADA) should include variable speed pump drives along
with proper instrumentation and controls. The system should be changed from a variable
temperature/constant flow system to variable flow and temperature. The installation of a
computerized SCADA system and the variable speed pump drives will regulate the hot
water flow according to the heat demands in specific sections of the network resulting in
energy efficient operation.
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50
4.7
REHABILITATION BENEFITS
The table below summarizes the anticipated benefits of implementing the Rehabilitation
recommendations described in Sections 4.1 to 4.5.
REHABILITATION BENEFITS
CHARACTERISTIC
BEFORE
AFTER
% IMPROVEMENT
Boiler Main Steam Flow,
166~206
220
~15.5
t/h
Boiler Efficiency, %
85~87.5
91.8
5~6
Turbine/Generator
100
105
5.0
Output, MWe
Heat Rate, kcal/kWh
2345
1990
15.1
Units Life Extension
-
15 years
Increase in Units
-
10 to 12%
10 to 12%
Availability
Benefits will also be realized from the Instruments and Control System modifications. The
implementation of these recommendations will improve the general operations of the boiler and
turbine by increasing its availability and reliability, decreasing Operating and Maintenance costs,
and extending the life of the units. The implementation of air pollution control recommendations
will help improve the air quality (environment) in the vicinity of the plant. The Low NOx burners
will lower the NOx discharge from the boilers and should allow the plant to meet future
environmental pollution limits. In addition, the improvements to the ESP's will greatly reduce the
amount of particulates that are expelled into the atmosphere from the plant stack.
The improved boiler and steam turbine efficiencies will result in decreasing the fuel consumption
for a given quantity of electric power generation (MW hrs). This will have the double benefit of
fuel cost savings as well as reduction in pollutants discharged to the environment. The estimated
15 years life extension of major plant components (boilers, turbines, condensers, feed pumps,
feedwater heaters, etc) as a result of the rehabilitation will defer the potential capital expenditure
needed to replace the plant capacity. If no rehabilitation were to be performed and the plant had
to be retired in the near future, it will require substantial capital investment. The plant
rehabilitation will also result in reducing the potential cost of replacement power to be purchased
if certain units of the plant were to be shutdown due to unplanned (forced) outages.
One additional benefit of the rehabilitation is an increase in plant availability and reliability due to
major renovation and upgrade of critical plant components such as boilers, turbines, auxiliary
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51
plant equipment and Instrumentation and controls upgrades. It is estimated that the availability
and reliability will improve by 10 to 12 percent as a result of the proposed rehabilitation.
The district heating system improvements will result in the following benefits.
The district heating piping network rehabilitation will result in substantial reduction
in heat and water losses due to improved piping and insulation of the system. It
will minimize the external corrosion of the piping system and extend the piping life
by at least 15 years.
The installation of variable speed pump drives will reduce electric power
consumption significantly resulting in substantial cost savings.
The installation of automatic control system (SCADA) will improve the district
heating system operation by providing automatic control, regulation and
monitoring of system parameters which will result in energy efficient operation and
substantial cost savings.
Installation of heat controls and energy meters at the end user (customer) houses
will reduce heat consumption resulting in energy savings for the system and
financial savings for the end users. The reduced fuel consumption will also reduce
enviornmental pollution.
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52
5.0
CAPITAL COST ESTIMATES
Cost estimates for the various rehabilitation items have been developed based on Burns and Roe
inhouse estimates for similar size jobs or from vendor estimates. The estimates are based on the
following scope of supply and are expressed in 1995 U.S. dollars.
Scope of Supply
Procurement of boiler and turbine NDE/DE equipment
NDE/DE of boilers pressure parts*
Replacement of 60% of furnace wall tubing*
Repair/Replacement of boilers pressure parts including superheater and economizer
inlet/outlet headers*
Repair/Replacement of boilers setting (BRILC)*
Refurbishment of tube penetration seals*
Repair/Refurbishment of tubular airheaters*
Repair/Replacement of fluegas ducting systems*
Field testing/repair of Draft Plants (ID and FD Fans)*
Repair/Replacement of Ball Mills and Auxiliary equipment*
Retrofit of a low NOx concentric firing system with either closed coupled or separate
overfire air*
Repair/Replacement of ESP's*
Refurbishment of boilers burner management system*
Repair/Replacement of boiler feed pumps*
Replacement of No. 3 turbine with new model KT-115/125-130
Replacement of electric generator and exciter for new turbine
Replacement of Condenser for new turbine
Replacement of feedwater heaters (2HP + 1D + 4LP)
Replacement of 50% of the main steam piping
Replacement of 50% of the extraction and drain piping and valves
Replacement of three (3) condensate pumps and motors
Replacement of two (2) Heater Drain Pumps
Replacement of two (2) Circulating Water Pumps
Installation of two (2) District Heating Heat Exchangers
Installation of three (3) DH Water Circulating Pumps
Installation of four (4) DH Heat Exchanger Drain Pumps
Installation of interconnecting piping and valves (Turbine to DH heat exchangers
(DHX), DHX to Condensate System, and to DH water system)
Install Instruments and Controls for heat supply regulation
*To be performed on all three boilers
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53
Installation of various boiler and turbine I&C components
Repair or replacement of damaged DH piping and piping insulation
Replacement of varioius DH booster pumps
Installation of a SCADA System and variable speed pump drives
Installation of heat controls and energy meters at end users
The project cost estimate is conceptual in nature, and was based on information obtained during
Burns and Roe's site visit in March 1995.
Direct Cost
Pricing for major equipment and materials were developed from Burns and Roe historical data
and vendor estimates for similar sized projects escalated to October 1995. The pricing is based
on major equipment and material being supplied by Western manufacturers and transported to the
project site.
Bulk materials (concrete, piping, valves, etc.) were assumed to be available locally in the
quantities and sizes necessary to support the project requirements.
Construction Labor
Labor costs were generated by using U.S. Gulf Coast manhour estimates for the work to be
performed and applying a productivity factor. The productivity factor was developed based on
Burns and Roe's observations at the site and previous studies performed in NIS countries. Based
on our site visit, we expect the skilled labor required to complete the project will be available
locally to the project and within Kazakstan.
Indirect Costs
Ocean freight costs and insurance costs have been assumed at 7% of material costs.
Contingency has been added to the estimate to provide for risks and uncertainties associated with
the prices at the conceptual stage of design. Contingency was applied to the direct labor and
material costs.
Other Costs
Additional costs such as Engineering, Construction Management, Start-up Costs, Construction
Equipment, Interest During Construction, and Escalation have not been included in the base cost
but are presented for information purposes. These costs are listed on sheet 3 of the cost estimate.
These costs are applicable to similar electric power plant rehabilitation projects in the United
States. However, they may have to be modified for reconstruction projects in Kazakstan based on
local construction practices and traditions.
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54
PRELIMINARY COST ESTIMATE
REHABILITATION OF BOILERS No.'s 7, 10 & 13 and TURBINE No. 3
KARAGANDA COMBINED HEAT & POWER PLANT KAZAKSTAN
ITEM
LABOR
MAT'L
LOCAL
TOTAL
COST $
$
MAT'L COSTS
COST
REHABILITATION OF BOILERS
Remove Existing Burners (24 Total)
120,000
3,600
123,600
Install New Low NOx Burners & OFA System
725,000
1,300,000
50,600
2,075,600
Refurbish Existing Ball Mills & Classifiers
372,000
396,000
23,000
791,000
Repair PA/PC Ductwork & Fans
524,000
987,000
45,300
1,556,300
Boiler Refractory, Insulation & Casing Repair
490,000
955,000
43,400
1,488,400
Tube Penetrations & Seals
142,000
185,000
9,800
336,800
Repair Air Heaters
625,000
859,000
54,300
1,538,300
Replace 60% of Wall Tubing, SH & Economizer Banks
825,000
1,535,000
70,800
2,430,800
Repair Induced Draft Fans
126,000
375,000
15,000
516,000
Repair Flue Gas Ductwork
185,000
680,000
26,000
891,000
Perform Non-Destructive Testing (Allowance)
150,000
150,000
Perform Draft Plant Assessments on (3) Boiler Trains (Allowance)
90,000
90,000
TOTAL BOILER WORK
3,529,000
5,972,000
287,600
9,788,600
REHABILITATION OF TURBINE GENERATOR
Remove Existing Steam Turbine & Accessories
280,000
280,000
Install New 105 MW Turbine & Generator
459,000
12,000,000
373,800
12,832,800
Supply NDE Testing Equipment
0
25,000
0
25,000
TOTAL TURBINE WORK
739,000
12,025,000
373,800
13,137,800
DISTRICT HEATING SYSTEM
ABAI
Replace District Heating Booster Pumps
5,000
140,000
5,000
150,000
Replace/Repair District Heating Piping
200,000
3,100,000
100,000
3,400,000
Install Instruments & Controls
200,000
200,000
GREENHOUSES
Install Circulating Pumps
15,000
250,000
15,000
280,000
Replace/Repair District Heating Piping
300,000
2,300,000
200,000
2,800,000
Install Instruments & Controls
200,000
200,000
TOPAR
Install Instruments & Controls
200,000
200,000
ALL SYSTEMS
Expand Make-up Water System for District Heating
150,000
1,000,000
50,000
1,200,000
New SCADA System with Variable Speed D.H. Pumps
500,000
500,000
TOTAL DISTRICT HEATING SYSTEM
670,000
7,890,000
370,000
8,930,000
55
02/02/96
SHEET 1 OF 3
PRELIMINARY COST ESTIMATE
REHABILITATION OF BOILERS No.'s 7, 10 & 13 and TURBINE No. 3
KARAGANDA COMBINED HEAT & POWER PLANT KAZAKSTAN
ITEM
LABOR
MAT'L
LOCAL
TOTAL
COST $
$
MAT'L COSTS
COST
AUXILLIARY PLANT SYSTEMS
Replace Existing Condenser
252,800
1,600,000
55,600
1,908,400
Replace HP Feedwater Heaters
184,000
450,000
16,000
650,000
Replace LP Feedwater Heaters
169,600
325,000
11,800
506,400
Replace Feedwater Pumps (2)
48,000
550,000
1,400
599,400
Replace Main Steam Piping
94,400
187,000
2,800
284,200
Install New Extraction and Drain Piping/Valves
37,600
63,000
1,100
101,700
Replace Condensate Pumps (3)
78,800
162,000
2,400
243,200
Replace Heater Drain Pumps
20,000
35,000
1,700
56,700
Install District Heating Heat Exchangers within the Powerplant (2)
198,000
1,325,000
5,900
1,528,900
Install District Heating Water Circ Water Pumps in the Powerplant (3)
104,800
489,000
3,100
596,900
Install District Heating Heat Exch Drain Pumps in the Powerplant (4)
33,600
63,500
2,900
100,000
Install D. H. Heat Exch Piping/Valves within the Powerplant
68,800
84,000
2,100
154,900
TOTAL AUXILLIARY SYSTEMS WORK
1,290,400
5,333,500
106,800
6,730,700
INSTRUMENTATION & CONTROLS
Install Emissions Monitoring Equipment (3 Systems)
516,000
1,695,000
44,200
2,255,200
Install Boiler Monitoring Equipment (3 Units)
224,200
767,700
19,800
1,011,700
Install Turbine Monitoring Equipment
115,700
290,600
8,100
414,400
Miscellaneous Instrumentation & Controls (3 Units)
202,700
1,635,000
36,800
1,874,500
TOTAL INSTRUMENTS & CONTROLS
1,058,600
4,388,300
108,900
5,555,800
ELECTRICAL SYSTEM
Repair Plant Wiring & Cable
432,000
1,645,000
21,700
2,098,700
TOTAL ELECTRICAL WORK
432,000
1,645,000
21,700
2,098,700
ENVIRONMENTAL SYSTEM
Remove Existing Precipitator (3)
453,600
9,100
462,700
install New Electrostatic Precipitator (3)
1,041,000
6,450,000
149,800
7,640,800
TOTAL ENVIRONMENTAL WORK
1,494,600
6,450,000
158,900
8,103,500
SUBTOTAL
9,213,600
43,703,800
1,427,700
54,345,100
Freight
3,297,900
Contingency (10%)
4,711,200
TOTAL COST OF REHABILITATION
62,354,200
ALL COSTS ARE SHOWN IN JANUARY 1996 DOLLARS
02/02/96
SHEET 2 OF 3
56
IF THIS PROJECT
...RE TO BE CONSTRUCTED IN THE USA
THE FOLLOWING ADDITIONAL COSTS WOULD APPLY:
DIRECT COSTS FROM PREVIOUS PAGE
62,354,200
Engineering Costs
3,260,706
Construction Management Costs
1,630,353
Start-Up Costs
1,086,902
Construction Equipment Costs
1,750,000
Interest During Construction
4,988,336
Escalation
6,005,640
TOTAL COST INCLUDING THE ITEMS ABOVE
81,076,137
1. Freight Costs are assumed to be 7% of the Material Costs
2. Construction Equipment Costs assumes Equipment to be available locally to the project
3. Engineering Costs are assumed to be 6% of the Material Costs
4. Construction Management Costs are assumed to be 3% of the Material Costs
5. Start-up Costs are assumed to be 2% of the Material Costs
6. Interest during construction is calculated at 8% per year for 2 years for 1/2 the direct cost
7. Escalation is assumed to be 4% per year for 2 years
57
02/02/96
SHEET 3 OF 3
6.0
CONSTRUCTION SCHEDULE
The construction schedule for the rehabilitation recommendations described in Section 4.0 is
shown on the following two pages. The overall duration of the reconstruction (rehabilitation)
project is estimated at 24 months based on Burns and Roe past experience with similar
rehabilitation projects. Time period of 24 months only includes the actual reconstruction of the
power plant components and their startup and checkout activities. It does not include the
engineering and design time required for rehabilitation of plant components such as boilers,
turbines, auxiliary plant system components, Instrumentation and controls, and electrostatic
precipitators (ESPs); nor does it include time required for procurement of the new equipment
such as ESPs and new instruments and controls, or the time required for the NDE of boiler
pressure parts.
5909-98A/KARA_DOC/2/2/96
58
CONSTRUCTION SCHEDULE OR THE KARAGANDA PLANT
Tasks
Month 1
Month 2
Month 3
Month 4
Month 5
Month 6
Month 7
Month 8
BOILER WORK
Test and Remove Deteriorated Boiler Components (Burners, Tubes, etc.)
Test and Remove Boiler Auxiliary Equip. (Mills, Fans, etc.)
Install New Mech. Components Including Heat Transfer Surfaces
Refurbish Mills and Auxiliaries
Repair Boiler Casing, Refractories, Insulation, etc.
TURBINE GENERATOR
Perform NDE Tests on selected Components
Replace Various Piping System Components and Valves
Install New Turbine/Generator and Auxiliaries
Install New DH Interconnection Piping, Valves, and Components
AUXILIARY PLANT SYSTEM
Replace Feedwater and Condensate Pumps
Replace Feedwater Heaters
Replace Condenser
Replace Associated Condensate Piping and Valves
ENVIRONMENTAL
Replace Electrostatic Precipitators
INSTRUMENTATION
Install Emissions and Air Flow Monitoring Equipment
Install Boiler and Turbine Monitoring Equipment
Misc. Instrumentation & Controls Systems Upgrades
DISTRICT HEATING SYSTEM
Repair and/or Replace Deteriorated Piping Sections
Install New District Heating Pumps
Install New Instruments and Control System (SCADA)
STARTUP AND CHECKOUT
Page 1
CONSTRUCTION SCHEDUL. JR THE KARAGANDA PLANT
Month 9
Month 10
Month 11
Month 12
Month 13
onth 1
Month 15
Month 16
Month 17
Month 18
Month 19
Month 20
Month 21
Month 22
Month 23
Month 24
Page 2
Burns and Roe Enterprises, Inc.
Technical Report
KAZAKSTAN EXPANDED ENERGY PROGRAM
HEAT AND POWER SYSTEM EFFICIENCY
IMPROVEMENTS
UST-KAMENOGORSK
THERMAL ELECTRIC STATION
FINAL REPORT
January 1996
Prepared by:
Burns and Roe Enterprises, Inc.
Submitted to:
U.S. Agency for International Development
The Government of Kazakstan
Contract No. :
CCN-0002-Q-09-3154-00
Heat and Power System Efficiency Improvements
Delivery Order No.9, Task 2
61
TABLE OF CONTENTS
KAZAKSTAN EXPANDED ENERGY PROGRAM
TASK 2
HEAT AND POWER SYSTEM EFFICIENCY IMPROVEMENT
UST-KAMENOGORSK THERMAL ELECTRIC STATION
1.0
Introduction and Objective
2.0
Kazakstan Energy Sector Strategy
3.0
Station Description and Evaluation
3.1
Steam Boilers
3.2
Steam Turbine Generators and Auxiliaries
3.3
Instrumentation and Controls
3.4
Air Pollution Controls
3.5
District Heating System
4.0
Station Recommendations
4.1
Energy Supply and Demand Situation
4.2
Steam Boilers
4.3
Steam Turbine Generators and Auxiliaries
4.4
Instrumentation and Controls
4.5
Air Pollution Controls
4.6
District Heating System
4.7
Rehabilitation Benefits
5.0
Capital Cost Estimates
6.0
Construction Schedule
5909-98C/UST-TOC.DOC/2/9/96
i
ABBREVIATIONS
CIS
Community of Independent States
USAID
U.S. Agency for International Development
CCE
Capital Cost Estimate
CHP
Combined Heat and Power
TES
Thermal Electric Station
LHV
Lower Heating Value
OD
Outside Diameter
PA
Primary Air
PC
Pulverized Coal
NDE
Non Destructive Examination
HP
High Pressure
IP
Intermediate Pressure
LP
Low Pressure
NOₓ
Nitrogen Oxides
SO₂
Sulfur Dioxide
ESP
Electrostatic Precipitators
I&C
Instrumentation and Controls
OFA
Overfire air or bulk furnace air staging
LNB
Low NO, burner
WEIGHTS AND MEASURES
at abs. or g
atmosphere absolute or gage
Gcal
Gigacalorie (10⁹ cal)
MW
Megawatt (10⁶ Watt)
kW
kilowatt (10³ Watt)
kg
kilogram
kV
kilovolt
kWh
kiloWatt hour
MVAR
Megavolt-Ampere Reactive
kg/cm²
kilograms per square centimeter
t/h or te/h
tons per hour (metric)
RPM
Rotations per minute
BTU
British Thermal Unit
MMBTU
Million BTU heat input
CONVERSION FACTORS
1 GCal = 4.187 GJ = 3.968 X 10⁶ BTU = 1,163 kWh
5909-98C/UST-TOC.DOC/2/9/96
ii
13
1.0
INTRODUCTION AND OBJECTIVE
The dissolution of the Soviet Union in 1991 resulted in the formation of five new independent
republics in Central Asia: Kazakstan, Kyrgyzstan, Uzbekistan, Turkmenistan and Tajikistan. Of
these, Kazakstan is the largest republic in terms of physical size and second largest in population.
Its physical size (area) is more than the area of the other four republics combined.
Kazakstan is a vast country with an abundance of valuable resources, including abundant energy
reserves and a large industrial base. Unfortunately, the collapse of the former Soviet Union has
resulted in economic dislocations throughout the central Asian republics including Kazakstan.
The transition from a command economy to a market economy has been painful to the population.
Industries which are no longer subsidized and protected by the former Soviet Union must be able
to survive in a more competitive market place. This has resulted in a severe economic recession.
The current economic recession has adversely affected the country's economy, including the
slowdown in the energy industries.
The majority of the thermal and heating plants in Kazakstan are over 20 years old and are
operating with obsolete equipment or with components requiring renovation. Maintenance
schedules do not allow for high availability of the units. In addition, many plants are obliged to
fire non-design fuel (e.g. coal with ash content exceeding the maximum design specification).
These problems combine to decrease power and heat production levels by as much as 20-40%
from the design capacities. The impact of the reduced power production has been moderated in
the past few years by a decrease in demand due to industrial recession. Reduced heat production
often results in domestic heating black-outs.
The shortfall in energy production will continue if the plants are not rehabilitated in the future; and
as Kazakstan grows into a market-led economy, the demand will accelerate and lack of available
energy will, potentially, become the limiting factor in the economic development of the country.
Increasing the efficiency of existing plants, extending their life and implementing a consumer
energy saving program are the most cost effective means for increasing energy independence.
However, the necessary renovation and maintenance costs are large. A plan for a consumer
energy savings program is being developed separately by a joint effort of the Ministries of
Economy and the Ministry of Energy and Coal. This separate effort is also supported by USAID.
USAID has recognized the seriousness of these problems, and has authorized this task for Burns
and Roe to assess the situation relative to Heat and Power Plant Efficiency Improvements. The
work covered by this report addresses the assessment of selected units at four different locations
in Kazakstan. The UST-Kamenogorsk Thermal Electric Station is one of the selected plants for
energy efficiency improvements study.
The objective of this project is to assess the costs and benefits of the efficiency and energy
production improvements which can be achieved by renovating and extending the life of the
5909-98C/UST.DOC/2/9/96
1
64
selected units. This report may serve as a basis for domestic and foreign investment
considerations.
The work covered by this report included the following tasks:
Background data related to the project was collected and analyzed. Meetings
were held with Kazakstani engineers to discuss the collected data.
A condition assessment was performed to identify the major plant systems and
components which require rehabilitation or modernization.
An engineering analysis was performed to determine the district heating system
deficit for the Ust-Kamenogorsk districts. After establishing the heating capacity
deficit, recommendations were made to install new line 7 which includes Boiler
No. 16 and Turbine No. 12. This analysis also included development of capital cost
estimates and implementation schedules.
A review of the Ust-Kamenogorsk District Heating System piping was made with
District Heating system engineers. Recommendations were developed to improve
system efficiency and reliability based on the information provided by the DH
system engineers.
The results of the engineering analysis will be reviewed with Kazakstani
authorities. The Kazakstani authorities may extrapolate the results of this analysis
to other combined heat and power plants in the country.
5909-98C/UST.DOC/2/9/96
2
2.0
KAZAKSTAN ENERGY SECTOR STRATEGY
The Kazakstan Power System currently consists of 64 electric power stations with a total capacity
of 16,026 MWe. These 64 plants include 40 Thermal Electric Power Stations (TES), with a
capacity of 13,897 MWe. The other 24 plants are electric generating stations and hydroelectric
power stations. The TES units provide district heat or process steam to the industries in addition
to electric power generation whereas the remaining 24 plants only provide electric power. The
main fuel used in these plants is coal. A breakdown of the fuel usage is shown below:
Fuel
Percent
Coal
74.3%
Petroleum (Oil, etc.)
12.2%
Natural Gas
14.5%
The main goals of Kazakstan Energo, as determined by the Ministry of Energy and Fuel
Resources are:
1.
To refurbish the current power plants operating in Kazakstan to improve their
efficiency, reliability, and reduce emissions to the environment.
2.
To commission new generating facilities with environmental controls to meet the
future shortfall in production capacities.
3.
To institute energy savings and conservation programs for consumers of heat and
electricity.
4.
To upgrade the current power plants with state of the art technology.
5.
To gradually bring the prices of heat and electricity up to the current world price
levels in a transition to a market based economy.
6.
To develop a new management structure for the power, heat generation, and
distribution industry.
Kazakstan currently imports electricity from Russia and other central Asian countries. In 1992,
Kazakstan imported 14 billion kWh of electricity. The gap between demand and installed capacity
is approximately 2,000 MW. Thus, there is a great need to install new generating capacity and to
refurbish the existing plants. Over the next 20 years, Kazakstan plans to create a reserve capacity
of approximately 20 to 25 percent.
During this period of upgrading and installing new capacities, a major focus will be placed on
environmental issues and energy conservation. As new legislation is enacted to help preserve the
5909-98C/UST.DOC/2/9/96
3
66
environment, the power sector must upgrade its environmental control equipment at heat and
power generating stations. Installation of NOx and SO₂ reducing technologies and improved ash
collection equipment will be required on all new and refurbished power plants.
The amount of pollutants released into the atmosphere can also be reduced by instituting energy
conservation programs as these programs would result in curtailing energy demand and hence
energy production. These programs could consist of gradual increase in tariffs on electric and
thermal energy, sanctions on the irrational use of energy resources, incentives to utilities that
conserve energy, and installation of more energy efficient appliances and industrial processes.
Another benefit of energy conservation program is the decreased demand for new energy
production capacities which will defer the capital investment for construction of new facilities into
the future. This will result in substantial financial benefit to the power generation industry in
Kazakstan.
5909-98C/UST.DOC/2/9/96
4
3.0
STATION DESCRIPTION AND EVALUATION
3.1
STEAM BOILERS
General
The Ust-Kamenogorskaja TES was commissioned in 1947 to supply electric power and district
heating to the City of Ust-Kamenogorsk. The Plant was designed to run on a heating time-table
with 4300 to 5200 hours of operation per year. At present, the Plant has eleven (11) pulverized
coal fired boilers (No. 5-15) with a total design steaming capacity of 2230 te/h and eight (8)
steam turbines with a total gross power output of 241.5 MWe. The boilers were designed to fire
Kuznetsk basin high volatile bituminous coal. The presently fired high volatile bituminous coal is
from the Shubarkul mine, Kazakstan. The water and mineral matter contents of this coal are
similar to those of the design coal, but the calorific value is somewhat less (see comparison later).
Boilers No. 5 to 10 are type CKTI-75-39F, manufactured by Barnaul Boiler
Manufacturing Co. The design parameters of these boilers are 75 te/h steamflow each at
39 at.g. pressure and 435°C temperature, 150°C feedwater temperature to the economizer,
150°C airheater exit fluegas temperature and 90.7% boiler efficiency (LHV basis). These
are drum type natural circulation boilers, with a conventional two-pass configuration,
balanced draft radiant furnace with fully water cooled tubewalls, and spaced tubes with
refractory backing. The superheater is a pendant style (non-drainable). The horizontal
drainable three stage economizer has a bare tube staggered arrangement with water in
upflow and fluegas in downflow. The three stage airheater is the tubular type, fluegas in
the tubes and air over the tubes in crossflow. The economizer and airheater tubebanks are
located in the rear convective passes. The furnace has a dry bottom ash disposal system.
The boilers are top supported, allowing for cubic thermal expansion. The indirect
(pulverized coal storage) coal firing system consists of a single subatmospheric operating
pressure ball mill per boiler. These mills are model SBM 250/390 with an external static
classifier, separating cyclone, pulverized coal storage bin with PC feeders, pulverized
coal/primary air (PC/PA) conduit system, and a mill fan which is a combined
exhaust/primary air fan. Each boiler furnace has three swirl type horizontal PC burners in
a single row, positioned in the front wall plus two start-up PC burners, one in each furnace
sidewall. The draft plant of each boiler consists of a single forced draft and induced draft
fan. All of the fans of each boiler are radial flow, centrifugal type, with electric motor
drive. Each boiler furnace has six tubewall sootblowers three in each sidewall. Particulate
emission control equipment consists of wet venturi type scrubbers, a single venturi and
two scrubbers per boiler.
Boilers No. 11 to 14 are type BKZ-320-140, and are also manufactured by Barnaul. The
design parameters of these boilers are 320 te/h steamflow each at 140 at.abs. pressure, and
555°C airheater exit fluegas temperature and 91.2% boiler efficiency (LHV basis). These
5909-98C/UST.DOC/2/9/96
5
68
boilers are also of the drum type with natural circulation and a conventional two-pass
configuration, balanced draft radiant furnace with fully water cooled tubewalls, and
tangent tubes with insulation and casing. The superheater stages are pendant, non-
drainable, with a spray type desuperheater interstage. The spraywater is generated from
condensed saturated steam in a heat exchanger using feedwater from the first stage
economizer outlet as the cooling medium. The horizontal drainable two-stage economizer
has a bare staggered tube arrangement with water in upflow and fluegas in downflow.
The three stage airheater is the tubular type with fluegas in the tubes and air over the tubes
in crossflow. The economizer and airheater tubebanks are located in the rear convective
passes. The furnace has a dry bottom ash disposal system. The furnace and top of the
rear convective pass are top supported, allowing for cubic thermal expansion. The lower
portion of the rear convective pass is bottom supported, with a metal expansion joint to
compensate for the downward/upward thermal expansions situated between the last stage
tubular airheater and second stage economizer. The indirect (pulverized coal storage) coal
firing system consists of two subatmospheric pressure ball mills per boiler. These mills are
model SBM 287/470 with an external static classifier, and separating cyclone. Each boiler
has a single, common pulverized coal storage bin with PC feeders. Each boiler has two
PC/PA conduit systems and two mill fans which are combined exhaust/primary air fans for
conveying the PC/PA mixture to the burners. Each boiler furnace has eight swirl type
horizontal PC burners arranged in two rows of four and positioned in the furnace
frontwall. Each burner has a steam atomized mazut gun for start-up and combustion
stabilization. The draft plant of each boiler consists of two FD and ID fans. Hot air
recirculation from the final stage airheater air outlet into the FD fan suction side is used to
protect the cold end of the tubular airheater from low temperature corrosion attack. All
the fans are radial flow, centrifugal type, with an electric motor drive. The number of
installed furnace tubewall sootblowers is not indicated in the documentation we have
received. No retractable sootlances are installed for the pendant superheater stages and no
heating surfaces cleaning equipment is shown for the economizer and tubular airheater
heating surfaces in the rear convective passes of the boilers. Particulate emission control
equipment consists of four venturi wet scrubbers per boiler.
Boiler No. 15 is type TPE-430/D, manufactured by Taganrog Machine Building Co. The
design parameters of this boiler are 500 te/h steamflow at 140 at.abs. pressure and 560°C
temperature, 230°C feedwater temperature to the economizer, 130°C airheater exit
(diluted) fluegas temperature and 90.5% boiler efficiency (LHV basis). The boiler is of
the drum type with natural circulation and large bore downcomers with small bore supply
tubes to the bottom furnace tubewall headers. The boiler configuration is the conventional
two-pass, with a short horizontal convective pass and a furnace arch with a modern
aerodynamic layout. The radiant furnace operates with a balanced draft and is constructed
with fully water cooled tube-fin-tube welded (membrane) walls, insulation and lagging.
The superheater consists of four stages with three interstage spray type desuperheater
stations. The low steam temperature superheater stages are radiant wall type (furnace,
horizontal and vertical convective passes roof, convective passes rear and sidewalls,
5909-98C/UST.DOC/2/9/96
6
69
furnace rear, front and sidewalls at the level of the lower furnace horizontal exit plane),
the third stage superheaters is of the nondrainable pendant convective type. The
spraywater is generated from condensed saturated steam in a heat exchanger using
feedwater (prior to entering the economizer) as the cooling medium. The horizontal
drainable two-stage economizer has extended heating surfaces (fins) and a staggered tube
arrangement with water in upflow and fluegas in downflow. The boiler has two vertical
shaft rotary regenerative bi-sector airheaters (type RPV-68 Ljungstrom license) in
counterflow with combustion air in upflow and fluegas in downflow. Each rotor has three
sectors, two hot and one cold. The cold sector heating surface is enameled. Hot air
recirculation from after the airheater air side outlet is fed into the FD fan suction side and
is used for airheater cold-end corrosion protection. The rotor speed is 2 rpm, with an
electric motor drive. The economizer stages are positioned in the vertical rear convective
pass and the two regenerative airheaters are positioned immediately below the economizer
fluegas side exit.
The indirect (pulverized coal storage) coal firing system consists of two subatmospheric
pressure ball mills per boiler, model SBM 320/570. Each of the mills has an external static
(centrifugal) classifier, separating cyclone, and pulverized coal storage bin with PC
feeders. The two separating cyclones are cross-connected to the two pulverized coal
storage bins. Each bin has four PC feeders for a total of eight per boiler. The coal
drying medium is hot fluegas taken from the furnace frontwall, above the lower
furnace horizontal exit plane by two high temperature fluegas ducts of stainless steel
construction and discharging into each ball mill raw coal inlet side. Classifier exit
mixture temperature control is by cold fluegas recirculation, using a recirculating
fan, with a fluegas tap-off downstream of the two ID fans and discharging into the
hot fluegas-to-ball mills lines. The boiler has two fluegas/PC conduit systems and two
mill fans which are combined PC and fluegas mixture circulating/conveying fans (for
conveying the fluegas/PC mixture to the burners). The boiler furnace has a total of eight
"flat-flame" pc burners, four burners each in the front and rear furnace walls, arranged in
single horizontal rows. Heat input capacity of each burner is 46.5 MWt. Each burner
consists of two hot combustion (secondary) airducts with an included angle of 60 degrees,
a pulverized coal/fluegas injector, a steam atomized mazut gun for ignition and load
stabilization and a flame scanner. Each mill fan also supplies vented fluegas plus
evaporated coal moisture together with some carryover pulverized coal to four vent
burner openings arranged in one of the furnace sidewalls with a total of eight vent burner
openings per furnace.
The draft plant of the boiler consists of two FD and three ID fans. All fans are radial flow
centrifugal type, with electric motor drive. The number of installed furnace tubewall
sootblowers is not indicated in the documentation we have received and neither is the
number of installed retractable sootlances. No heating surfaces cleaning equipment is
indicated for the economizer and for the two rotary regenerative airheaters. Particulate
emission control equipment consists of five venturi wet scrubbers per boiler. A water
5909-98C/UST.DOC/2/9/96
7
impounded bottom ash/slag hopper supported on the basement floor is installed below the
furnace tube hopper. Four combined electric motor driven screw conveyors/ash crushers
are installed per bottom hopper for the removal of the bottom ash. The type of seal
between the furnace tube hopper and the water impounded bottom ash hopper is not
indicated.
Table 3-1 shows a comparison of the Kuznetsk and Shubarkul coals that have been used at the
plant.
5909-98C/UST DOC/2/9/96
8
TABLE 3-1
Kunzetsk Basin and Shubarkul Mine Bituminous Coals Characteristics Comparison
Parameter
Unit
Kuznetsk grades
Shubarkul
G&D
Volatiles DAF
% by wt.
38 to 45
45
LHV
kcal/kg
5240 to 5450
4700
Total moisture (max.)
% by wt.
18.2
20
Grinding factor, Russian
---
1.23 to 1.35
1.30
(Kpo)
HGI (=Kpo-0.32/0.0149)
---
61 to 69
66
Ultimate analysis, as fired:
Carbon
% by wt.
55.5 to 58.7
48.5
Hydrogen
% by wt
3.9 to 4.2
3.4
Oxygen
% by wt
8.9 to 9.7
14.8
Nitrogen
% by wt
1.7 to 1.9
0.9
Sulphur
% by wt
0.3 to 0.5
0.4
Total moisture
% by wt
12 to 12.7
15.0
Mineral matter
% by wt
13.2 to 17
17.0
Mineral matter chemical composition:
SiO2
% by wt
N/A
67.0
A12O3
% by wt
N/A
23.0
Fe203
% by wt
N/A
3.5
TiO3
% by wt
N/A
1.1
CaO
% by wt
N/A
2.0
MgO
% by wt
N/A
1.0
K20
% by wt
N/A
1.2
Na2)
% by wt
N/A
0.5
SO3
% by wt
N/A
0.1
Ash fusibility temperatures (assumed in a reducing atmosphere):
Initial deformation
°C
1030 to 1260
1350
Softening
°C
1050 to 1300
1450
Hemispherical
°C
1100 to 1400
N/A
Flow
°C
1550
1500
N/A = Not Available
5909-98C/UST.DOC/2/9/96
9
Condition Assessment
Type CKTI-75-39F (Boilers No. 5 to 10)
These six boilers were installed between 1952 and 1957, and their operating periods range
from 166,000 to 137,000 hours, as of March 31, 1995. Boiler #9 had the largest number
of total starts (864) while boiler #10 has the least (623), also as of March 31, 1995. The
other four CKTI boilers had an average of 730 total starts. Breakdown of the total
number of starts by type (cold, warm, hot, restart) is not provided. The steam outputs of
these boilers are significantly derated (by an average 27%), the LHV basis boiler
efficiencies have also deteriorated substantially from the design of 90.7% to an average of
75.6%. Each of the boilers has an average of 5 to 6 annual unscheduled shutdowns due to
equipment breakdowns. The main operating problems are furnace and boiler
refractory/insulation/casing damage, furnace tubing cold side low temperature corrosion
attack, unmeasured ambient air ingress into the furnace/boiler setting, excessive
superheater tube metal temperatures, and low temperature corrosion attack of economizer
and tubular airheater tubebanks. We postulate, based on the long periods of operation,
that the final superheater tubebanks and outlet headers have some initial creep damage and
that the first stage economizer inlet headers have fatigue cracks. Plant personnel have not
reported any fatigue type cracks of the steam/water drums to the BRC team. Low quality
(shop/field) welds of boiler tubes are another source of frequent breakdowns. Considering
the very high (90%) total SiO2 plus Al203 content of the now fired Shubarkul coal
mineral matter (ash), both the convective pressure parts as well as the firing system
components, e.g., PC/PA conduits, classifiers, separating cyclones, ball mill liners, must
have substantial erosion wear type metal loss. Erosive wear is likely to affect the
availability of the wet venturi scrubbers and the ID fans.
Type BKZ-320-140 (Boilers No. 11 to 14)
These four boilers were installed between 1966 and 1970 with operating periods ranging
from 168,000 to 138,000 hours as of March 31, 1995. Boiler #11 had the largest number
of total starts (359), and boiler #14 the least (276), also as of March 31, 1995. The other
two boilers had an average of 330 total starts. Again, breakdown by type of starts is not
provided. Steam outputs of these boilers are also derated (by an average of 16%) and the
LHV basis boiler efficiencies have deteriorated from the design 91.2% to an average of
84.9%. The number of average annual unscheduled shutdowns of these boilers, due to
equipment breakdowns is similar to that of the CKTI boilers. The main operating
problems are also the same as for the CKTI boilers. Some initial creep damage of high
temperature metal pressure parts is anticipated due to the relatively long operating
periods. We also anticipate fatigue type cracking of the first stage economizer inlet
headers at tube ligaments and a slight possibility of some fatigue damage of the
steam/water drums. Metal loss due to erosive wear of convective pressure parts, firing
5909-98C/UST DOC/2/9/96
10
system components, particulate emission control equipment and ID fans must also be a
significant operating problem due to the erosion propensity of the coal mineral matter.
Type TPE-430/D (Boiler No. 15)
This modern non-reheat utility boiler was installed in March of 1991 and had an operating
period of approximately 15,000 hours and a total of 66 starts as of March 31, 1995.
Considering the low number of operating hours and total starts, it is somewhat unexpected
that the steam output is derated by 23% and that the boiler efficiency (LHV basis) has
deteriorated by 5% from the design value of 90.5%. According to Plant personnel, the
main operating problems of the boiler are (a) furnace tube failures by dry-out/overheating,
due to boiler mal-operation (very likely operation with too low steam/water drum water
level or even worse, complete loss of drum water level) and (b) low quality boiler tube
weld joints. The listed operating problems however, do not explain the substantial steam
output derate and the deteriorated boiler efficiency. The furnace has a fully welded
tubewall construction, thus unmeasured ambient air ingress into the setting should not
occur. The steam output derate may be due to deficient coal throughput capacity of the
ball mills or due to draft plant capacity deficiency.
3.2
STEAM TURBINE GENERATORS AND AUXILIARIES
Plant Description
The Ust-Kamenogorsk TES currently consists of 8 operating steam turbines with an electric
generation capacity of 241.5 MW. All turbines are of the heat supply type (back-pressure or
district heating). The rated heat supply capability for these units is 596 Gcal/h. In addition to this
nameplate capability the plant also provides thermal energy of 454.9 Gcal/h from main steam
headers through pressure reducing stations. The total present nameplate heat supply capability of
the plant is thus 1050.9 Gcal/h.
The net electric energy produced is distributed to consumers through the electric power
distribution system. Thermal energy is distributed to various industrial, commercial and
residential customers in the form of steam or hot water through a network of transmission and
distribution piping.
There are a total of 15 steam boilers in the plant which provide main steam to the turbines via two
main steam headers. The low pressure header operates at a pressure of 29 ata, and the high
pressure header at 130 ata. Boilers No. 5 through 10 feed steam to the low pressure header,
while boilers No. 11 through 15 supply steam to the high pressure header. The two headers are
connected through a pressure reducing station. Steam turbines No. 4 through 8 receive steam
from the low pressure header, and turbines No. 9 through 11 receive main steam from the high
pressure header. Figure 3-1 schematically illustrates the arrangement of the energy supply scheme
of the Ust-Kamenogorsk plant.
5909-98C/UST.DOC/2/9/96
11
Figure 3-1
UST- KAMENOGORSK ENERGY SUPPLY SCHEME
BEST AVAILABLE COPY
BOILERS
BOILERS
CONDITIONS FOR BOILER
16
14
13
12
"
CONDITIONS FOR BORERS
10
9
8
7
6
5
CONDITIONS FOR BOILERS
15
11 THRU 14
5 THRU 10
TYPE TRE-43DA
TYPE БКЗ-320-М0-2
TYPE 5K3-75-39
P= 140 ATA, T*555* C
P= MD ATA: T=555* C
P= 32 ATA, T=400*-435°C
A=500 T/HR
A=280 T/HR
A=75 T/HR
Q=298 GCAL/HR
0*367 GCAL/HR
0=46 CCAL/HR
HEADER 130 ATA
(
HEADER 29 ATA
D
TURSINES "
TURBINE M
TURBINE "
TURBINE #5
PRESSURE
AND #7
REDUCING
TURBINE en
TURBINE #10
TURBINE "
PRESSURE
STATION
TYPE T-100
TYPE T-50
TYPE P=38-130-34
REDUCING
(TVP)
STATION
(TYP)
H.P. HEATER (2)
HEADER " ATA
LP.HEATER (4)
LP. HEATER (4)
0
D
H.P. HEATER
HEADER 7 ATA
4
D
HEADER 12 ATA
+
D
FW HEATER
H.P. HEATER
H.P. HEATER
PLANT CONDENSERS
DISTRICT HEATING
HEAT EXCHANGERS
TO
DEAERATOR
TO STEAM
EXTRACTION STEAM
CONSUMERS
TO DEAERATOR
, ATA: 200 Gcalfr
1.2 ATA: " Gosthr
12
OL/USTRAM.DCM
BEST AVAILABLE COPY
Turbine No. 1 and 2 (manufactured by Westinghouse) and turbine No. 3 (a Ljungstrom design)
have been removed from service and dismantled. The existing units No. 4 through 11 were
placed in service between 1941 and 1970. Some of these units underwent modifications during
their operating lives. The year of initial service, the original and modified designations, the
present operating parameters, number of operating hours, and other relevant information are
given in Table 3-2.
Turbine No. 4 was manufactured by the Kaluga Turbine Plant and was placed into operation in
1959 with a nameplate rating of 6 MW. Its original designation was AP-6-5 and it was designed
for main steam parameters of 35 ata and 435°C. Since it actually receives steam from the low
pressure header at only 29 ata and 400°C, it has been derated to 3.5 MW. This turbine exhausts
to the 7 ata discharge header, which feeds steam to various services as outlined below. There are
no extractions from this turbine. There have been no modifications made to this turbine since it
was installed.
Turbine No. 5 was manufactured by Metropolitan Vickers in 1943 and was placed in operation at
this plant in 1951 as a 20 MW (AK-20) turbine which was designed for a main steam pressure of
35 ata and temperature of 435°C. While originally this turbine was a condensing unit, in 1982 it
was converted to operate in the back-pressure mode. This conversion included removal of the
blades of the last six stages of the turbine, removal of the condenser, and rerouting of the turbine
exhaust to the 1.2 ata discharge header which supplies steam to services as outlined below. The
turbine has a new designation, P-10-29/1.5, and a revised nameplate capacity of 10 MW. There
are no extractions from this turbine. The new main steam parameters for the unit are 29 ata
pressure and 400°C temperature. The maximum steam flow for the unit is 80 t/h.
Turbines No. 6 and 7 were manufactured by the Kirov Plant in 1951 with a type designation of
DK-20-120. Unit 6 started its operation at the Ust-Kamenogorsk Plant in 1951 and Unit 7 in
1952. They were condensing units with industrial and district heating extractions and had a
nameplate capacity of 12 MW. Turbine No. 6 was converted from condensing to backpressure
type in 1970, and Turbine No. 7 was similarly converted in 1974. These conversions included
replacement of the diaphragms of the HP section to accommodate revised steam flows,
elimination of the steam extractions, replacement of the LP rotor with a shaft thereby deactivating
the LP turbine, renovation of the control system, removal of the condenser, and rerouting the
turbine exhaust to the 7 ata header. The current nameplate capacity of each of these turbines is 8
MW, and they have a main steam flow rate of 150 t/h. They have been redesignated as P-8-29/7
type following the conversions.
Turbine No. 8 was manufactured by the UTMZ as an At-25-2 unit and placed in operation in
1954 with a nameplate rating of 25 MW. It was designed to receive steam from the low pressure
header at 29 ata and 400°C, and exhaust to a condenser. However, in 1966 the turbine was
converted from a condensing too backpressure type. This conversion included the replacement of
5909-98C/UST.DOC/2/9/96
13
TABLE 3-2
OPERATING CAPABILITY OF THE UST-KAMENOGORSK TURBINES
Steam Turbine No.
4
5
6
7
8
9
10
11
Year of Initial
1959
1951
1951
1952
1954
1967
1966
1970
Service
Original Designation
AP-6-5
AK-20
DK-20-120
DK-20-120
AT-25-2
P-38-130/34
T-50-130
T-100-130
Rated Original
6
20
12
12
25
38
50
100
Generating Capacity,
MW
Current Designation
P-3.5-29/7
P-10-29/1.5
P-8-29/7
P-8-29/7
P-25-29/1.7
P-38-130/34
T-50-130
T-100-130
Current Rated
3.5
10
8
8
25
38
48.8
100
Electric Capacity,
MW
Main Steam Flow, t/h
60
80
150
150
220
470
265
460
Current Main Steam
29
29
29
29
29
130
130
130
Pressure, ata
Current Main Steam
400
400
400
400
400
555
555
555
Temperature °C
Turbine
7
0.5
7
7
0.7
39
0.035
0.035
Backpressure
kg/cm²(a)
Accumulated
118,407
195,263
258,872
256,695
198,910
191,244
166,477
154,917
Operating Hours, Hr
Number of Starts
466
488
379
328
344
246
298
212
Year of Last Capital
1991
1992
1994
1992
1995
1995
1991
1993
Repair
5909-98C/UST.DOC/2/9/96
14
the diaphragms and the rotor of the HP section to accommodate revised steam flows, replacing
the LP rotor with a shaft thereby deactivating the LP turbine, removal of the condenser, rerouting
the turbine exhaust to 1.2 ata header and the replacement of the control system. The nameplate
capacity remains unchanged at 25 MW. The turbine has one steam extraction to an HP heater.
The turbine exhaust steam from the 1.2 ata header is used to heat district heating water in main
DH water heat exchangers. The current designation of this turbine is P-25-29/1.7.
Turbine No. 9 was manufactured by UTMZ in 1966 as a P-38-130/34 model and was placed in
operation in 1967 with a nameplate rating of 38 MW. The unit was designed for main steam
parameters of 130 ata pressure, 555°C and a main steam flow rate of 470 t/h. The turbine
receives steam from the high pressure header and exhausts to the same 29 ata header which
supplies steam to turbine No. 4 through 8, to pressure reducing stations and to HP heaters. The
HP heaters were replaced in 1986, but no modifications have been performed on this turbine and
no input/output limitations have been imposed since its initial installation.
Turbine No. 10 was manufactured by UTMZ in 1965. It is a T-50-130 district heating unit and it
was placed in operation in 1966 with a nameplate rating of 50 MW. It receives steam from the
high pressure header at 130 ata and 555°C, and exhausts to a condenser. The turbine has 7
extractions which supply steam to HP heaters 5 through 7, LP heaters 1 through 4, and hot water
heaters 1 and 2. In 1991 the blades of the 21st stage were removed because of erosion and
cracking, and the turbine currently operates under this condition. As a result, the electrical
capacity was reduced by 1.2 MW in the condensing regime and 3.8 MW in the heating regime.
The turbine has a nominal heat supply capability of 92 Gcal/h.
Turbine No. 11 was also manufactured by UTMZ (in 1969). It was placed in operation at the
plant in 1970 as a T-100-130 district heating unit with an electric nameplate capacity of 100 MW.
The design steam parameters are 130 ata, 555°C, and the turbine has a maximum steam flow
capability of 460 t/h. It is a 3-cylinder unit with a 2-flow LP section. The maximum district
heating capability of the controlled extractions is 160 Gcal/h. The turbine receives steam from the
130 ata header and exhausts to a condenser. The condenser has built-in tube banks which can be
used to pre-heat make-up water for the district heating network. The turbine has 7 extractions
which supply steam to HP heaters, a deaerator, LP heaters, and district hot water heaters. No
modifications have been performed on this turbine since its initial installation.
In addition to the above operating turbines, there is also a nominal 80 MW district heating turbine
(No. 12) at the plant in storage. This turbine was manufactured in 1993, has industrial steam and
district heating steam extractions, but has not yet been installed due to lack of funds. The turbine
pedestal and the condenser have been installed at the plant. Auxiliary equipment and piping have
also not yet been purchased due to lack of funds.
The actual operating performance of the installed turbines based on the average 1994 data is
shown in Table 3-3.
5909-98C/UST DOC/2/9/96
15
TABLE 3-3
OPERATING PARAMETERS OF THE UST-KAMENOGORSK TURBOGENERATORS
(Based on 1994 averages)
Unit No.
4
5
6
7
8
9
10
11
Electric Power Generation,
11,704
30,324
40,777
56,444
80,871
148,640
203,990
352,352
10' kWh
Average Electric Load, MW
3.0
8.0
6.9
7.9
17.6
27.4
42.3
78.4
Head Loads, Gcal/h
Total
32
32
72
73
81
88
321
Industrial
32
72
73
DH
31
81
86
131
Built-in Tube Bundles
2
1
Operating Hours, hrs
3,830
3,773
5,863
7,181
4,604
5,431
4,814
4,497
Electrical Energy Generated
11,704
30,324
40,777
56,444
80,871
148,640
181,360
328,442
in the Heating Mode, 10'
kWh
Number of Starts
17
11
16
10
15
11
8
6
Main Steam Pressure, ata
28.1
28.4
25.1
25.5
28.8
118.8
128.0
126.6
Main Steam Temp, °C
397
396
400
398
391
542
545
554
Industrial Steam extraction
pressure, ata
6.4
6.4
6.6
DH steam extraction
pressure, ata
1.2
1.3
1.1/0.9
1.0/1.0
Back-pressure, ata
6.4
1.2
6.4
6.6
1.3
33.0
Vacuum, %
95.3
95.3
Final feedwater
140
148
227
225
219
Temperature, °C
Specific Heat Consumption,
1,000
920
986
1,000
1,026
979
1,420
1,389
Kcal/kWh
5909-98C/UST.DOC/2/9/96
16
Condition Assessment
a)
Turbine Problems
The current installed electrical capacity of the Ust-Kamenogorsk Plant is 241.5 MW. However,
the actual operating capacity in 1994 was lower than the above value due to certain limitations
associated with equipment degradation. For instance the actual operating electrical capacity of
the plant at the beginning of the year was set at 244 MW. This is because of the 5 MW limitation
at the No. 8 turbine due to the breakage of the 20th and 21st stages, and 3.5 MW limitation at the
No. 10 turbine due to the breakage of the 21st stage blading. By the end of the year, further
degradation of output capability was noticed. This further degradation of about 9 MW was due
to the deterioration of the No. 5 electric generator stay ring insulation. Thus the plant electric
output capability at the end of the year 1994 was 224 MW. Thus the total degradation of the
turbine output capability was:
241.5 - 224 X 100 = 7.25%
241.5
Other problems with the individual units and auxiliaries are as follows:
The No. 4 steam turbine is the smallest unit and is 36 years old. There was an accident in
1977 involving this turbine steam path components. As a result, the rotor and the
diaphragms were replaced in 1978. However, the unit has had many problems with
cracking of the steam chest, stop valve, diaphragm packings, and governing oil system.
The cracking problem is still continuing, and even though the unit accumulated a relatively
low number of operating hours compared to the other machines, (about 20% over its
original design life). This unit should be removed from service as soon as new capacity
will be available.
Turbine No. 5 has accumulated a total operating time of 195,263 hours as of January 1,
1995. This is the oldest unit (52 years old) having been manufactured in 1943. The main
problems are due to the extreme old age of this unit and include:
-
The steam path components (blades, nozzles, diaphragms, disks) have
heavy corrosion wear.
-
The main oil pump does not provide sufficient pressure for turbine
lubrication and control.
-
The steam distribution and control parts are worn.
-
There are no design drawings for some turbine components.
5909-98C/UST.DOC/2/9/96
17
80
-
No tools and equipment are available to perform replacements or to
fabricate spare parts (all connections are in English measuring system, not
in metric).
This turbine should be disassembled as soon as possible.
Turbines No. 6 and 7 have accumulated the highest number of operating hours (258,872
hours and 256,695 hours, respectively), and are 44 years old. Besides the more than
double original design operating life, these units have the following problems:
-
Lack of spare parts.
-
Excessive wear of spring couplings between the HP rotor and "LP" shaft.
-
Cracks at the steam intake.
-
Unsatisfactory condition of turbine sealing rings.
-
Worn turbine lube oil cooler tubing system.
These units have very low remaining lives left.
Turbine No. 8 was installed 41 years ago and has accumulated a total operating life of
198,910 hours, almost twice its original design life. As it was noted above the output
capability of this unit has been degraded because of the complete absence of the 20th stage
blades and the partial removal of the 21st stage blades. In addition, this turbine has the
following problems:
-
Replacement of blades and disks of the 4th, 15th, 16th, 17th, 18th, 19th
and 20th stages is required because of their wear and tear over the years.
-
Physical wear of main steam stop valve and pressure control actuator.
-
Wear of the tubing systems of the turbine oil cooler and the generator seal
oil cooler.
-
Emergency (DC driven) oil pump for the generator seal oil system is
required to be installed.
-
Shortage of funds prevents the delivery of spare parts to rehabiltiate the
turbine.
5909-98C/UST.DOC/2/9/96
18
81
It should also be noted that the electric generators of all of the above units (Units 4
through 8) also have exhausted their useful lives.
The relatively younger units (turbines No. 9, 10 and 11) operating with the higher steam pressure
and temperatures have the following problems:
The Unit No. 9 steam turbine has accumulated a total number of operating life of 191,244
hours. Therefore
-
The stop valves on regulating valves have exceeded their park resource
which is 170,000 hours.
-
The steam leads to the turbine are very close to their extended useful life of
211,000 hours.
-
The cylinder and rotor also have very little remaining life (park resource
220,000 hours).
-
Turbine oil cooler tubing system needs replacement.
The Number 10 steam turbine is about 29 years old and has been operating for 166,477
hours as of January 1, 1995. As noted above, the blades of the 21st stage were removed
in 1991 because of wear and cracking, limiting the turbine output capability. The high
pressure feedwater heaters of this unit were replaced in 1992 and the LP heater #4 was
replaced in 1994. The main DH heat exchanger #2 tubes were also replaced in 1994. The
No. 10 steam turbine has the following problems:
-
The blades in stages #21, 22 and 23 should be replaced (blade life is
100,000 hours).
-
The steam leads to the turbine have very little useful life remaining.
-
The LP feedwater heaters #1, 2 and 3 and the gland steam condenser tubes
need replacement.
-
The expansion joints on the extraction steam lines to LP HTR #1 and #2
and to the main DH heat exchangers need replacement.
-
The turbine oil cooler tubing needs to be replaced due to leaks.
The No. 11 steam turbine is the youngest operating unit at the plant with a total of
154,917 accumulated hours of operation. This unit was reported to have a very low
5909-98C/UST.DOC/2/9/96
19
&
efficiency HP section mainly because the interstage seal strips at the shrouds and
diaphragms are practically absent.
Correction of this problem was said to require the replacement of the 2nd through
8th stage diaphragms. In addition the following problems exist with the No. 11
turbine:
-
The expansion joints in the extraction steam piping to the LP HTRS #1 and
2 and to the main DH heat exchangers need replacement.
-
The HP feedwater heaters need replacement.
-
The turbine stop valve needs to be replaced because of cracks.
-
The tubes of the LP feedwater heaters and the gland steam condenser
need to be replaced because of leaks.
The eight operating units had a total of 144 turbine generator related outages during the past 10
years. The dates and reasons for these outages are shown in Table 3-3.
The plant personnel does a good job in running the plant despite the many problems and the lack
of spare parts. The plant maintenance records for the 1994 year indicates the following repair and
availability figures:
Duration (hours)
Availability
Factor %
Turbine No.
Major Repair
Intern. Repair
Maintenance
Available Hrs
4
-
-
365
8,395
95.83
5
-
-
640
8,120
92.69
6
1,291
-
749
6,720
76.71
7
-
-
475
8,825
94.58
8
-
-
1,731
7,029
80.24
9
-
-
262
8,498
97.01
10
-
-
375
8,385
95.72
11
-
-
14
8,746
99.84
Based on the above durations the plant shows a weighted availability factor for the turbines of
95.25%.
In addition to the problems of turbine generators themselves, there are problems with the turbine
plant auxiliary equipment. Some of these components have been identified above under the
5909-98C/UST DOC/2/9/96
20
83
description of problems for the different turbines. Additional components or problems which
would require attention include:
Tube replacement for the No, 5, 6, 7 peaking DH heat exchangers.
Tube replacement of the main steam jet air ejector for the No. 10 turbine condenser.
Vacuum deaerator ejectors.
Turbine oil cooler tubing leaks.
The 5th phase 140 ata main steam pipe lines should be replaced (exhausted its service life).
Many of the pumps in the turbine plant exhausted their useful lives and operate with poor
efficiencies and without proper spare parts. These pumps should be replaced with new
modern designs. The pumps requiring replacement are as follows:
Pumps No. 1, 2 (1951 vintage)
Pumps No. 3, 4 (1954 vintage)
Pumps No. 5, 7 (1965 vintage)
Circulating Pumps No. 6, 9 (1951-1954 production)
Deaerated water pumps No. 1, 2 (1954 production)
Condensate and feedpumps for the Unit 10 turbine cycle (1965 production)
The deaerating columns of the low pressure deaerators No. 1 through 3 should be
replaced because of shell wear and tear.
b)
Metal Control
Metal control laboratory personnel were interviewed to assess the procedures and equipment the
plant has to monitor metal conditions. The equipment for non-destructive examination (NDE)
and destructive examination (DE) at the plant include:
Ultrasonic flow detector (UD2-12)
Magnetic Particle (MP) testing equipment
X-ray device
Hardness tester - portable
Hardness tester - stationary
Spectroanalific equipment
Chemical analysis equipment
5909-98C/UST.DOC/2/9/96
21
84
The plant also has liquid penetrant (LP) testing equipment but it is not frequently used. There are
no boroscopes or electronic microscopes at the plant. In addition there is no replication type
creep testing equipment currently at the plant. In 1985 the plant invited outside testing agencies
(Ekaterisburg, Cheljabinsk) to check the condition of the main steam piping at the elbows.
The plant follows the 1995 guidelines RD34.17.421 (Moscow) regarding the metal control of the
main components of boilers, turbines and piping systems in thermal power plants. The metal
control personnel usually look at the external parts of the turbines (outside of shell, stop valves,
steam chest, regulating valves) during regular maintenance. However, examination of the
internals of the turbines and valves, etc. can only be done during the capital repairs, about every
four years.
According to the metal control personnel, the main problems with their aging turbines are the
cracking of stop valves and the upper half of the turbine cylinders, as well as the erosion of the
last stage blades. During the past 10 years the following defects have been found on the various
turbines:
YEAR
DESCRIPTION OF DEFECTS
TURBINE NO. 4
1986
Cracks on cylinder cover with dimensions of
between 70 mm to 330 mm long and up to 20 mm
deep
1991
Cracks on cylinder cover with dimensions up to 90
mm long and 200 mm deep
1994
Cracks in the stop valve: 60 mm long and 25 mm
deep
TURBINE NO. 6
1994
Cracks on cylinder cover with dimensions of up to
80 mm long and between 10-15 mm deep
TURBINE NO. 7
1992
Cracks on the turbine cylinder with dimensions
between 80-100 mm long and 10-15 mm deep
5909-98C/UST.DOC/29/96
22
YEAR
DESCRIPTION OF DEFECTS
TURBINE NO. 8
1987
Crack on the cylinder cover: 210 mm long and 5
mm deep
1994
A network of cracks on the stop valve cover with
dimensions of up to 150 mm long and 25 mm deep
TURBINE NO. 9
1990
Cavities in the control valve fillets with diameters
between 5-6 mm and depth between 4-6 mm.
Cavities in the HP cylinder cover with diameters of
35 mm and depth between 5-7 mm.
Cavities in the stop valve with diameters between 5-
20 mm and depth up to 10 mm. Also surface cracks
with lengths of up to 200 mm and 1-2 mm depth.
TURBINE NO. 10
1991
Three cracks in HP cylinder cover with dimensions
up to 120 mm in length and 34 mm depth.
Ten cracks in the IP cylinder cover with dimensions
up to 180 mm in length and 40 mm depth.
TURBINE NO. 11
1993
Four cracks in the IP cylinder cover with dimensions
of up to 240 mm in length and 27 mm depth
Three cracks at the inner surface of the stop valve
with dimensions of up to 200 mm in length and 50
mm in depth.
The piping sections between the turbine stop valve and the control valves for Turbine No. 9, 10
and 11 are made of 12 Cr-1Mo-1V material and have dimensions with Φ243 X 30 mm, Φ219 X 26
5909-98C/UST.DOC/2/9/96
23
86
mm and Φ133 X 17 mm. No defects have been reported for these pipe segments. However, there
were cracks found on some of the high pressure (130-140 ata) main steam piping segments
between the type BKZ-320 steam generators and the high pressure turbines between the years
1981 to 1995. No defects were found on these segments during the prior period between 1966 to
1981.
As noted above, there is currently no replication type creep testing capability at this plant. As the
plant increases in age such testing capability would be highly desirable to monitor potential creep
damage of critical components which operate with units approaching the end of their extended
design life (park resource operating hours). Utilization of such testing equipment would enable
the plant to better predict potential failures or to perform predictive maintenance.
3.3
INSTRUMENTATION AND CONTROLS
General
The instrumentation at the Ust-Kamenogorsk plant is relatively new when compared to other
Kazakstani plants we have inspected. The boiler control system, and the supervisory and
protection systems, are well designed. Most control loops use electronic controllers. The lack of
spare parts and insufficient maintenance significantly degraded performance of the control and
supervisory systems. The recommended action involves addition of some instrumentation,
particularly in the environmental control area and better instruments for the boiler control area.
The following is a assessment of Ust-Kamenogorsk Instrumentation and Control System based on
the information collected during the plant visit and discussions with the plant management.
(a)
Air Flow Control
This is purely a manual function carried out by varying the position of the forced draft fan radial
inlet vanes remotely from the control room. An O₂ indicating system fed from an oxygen analyzer
assists the unit operator in setting the correct combustion air flow rate. Each of the two 50%
forced draft fans used for the HP boilers are electric motor driven, centrifugal type with radial
flow. The original oxygen analyzers are extractive type and consequently slow acting. The low
pressure boilers have only one forced draft fan, however both boilers use two speed fans with
adjustable vanes.
(b)
Primary Air Temperature Control
A portion of hot flue gas is injected into coal mills for temperature and oxygen control. This is to
reduce the possibility of coal explosions. The PA fans are not, however, cross connected so that a
single fan shutdown trips the boiler. This system uses electronic controllers and works
satisfactorily.
5909-98C/UST.DOC/2/9/96
24
(c)
Furnace Pressure Control
Furnace pressure is controlled in a closed loop system using pressure as the controlled variable.
Each induced draft fan is equipped with inlet vanes which are modulated to control furnace
pressure.
(d)
Steam Temperature Control
Steam flow is divided into two parallel paths, with steam crossovers at the first and second spray
attemperator stages. There is an attemperation system in the parallel steam paths to the first and
second stage desuperheaters using spray water attemperation valves each with its own dedicated
controller. The spray water source is steam taken from the drum which is then condensed in a
heat exchanger where the cooling medium is the feed water flow just before entry to the drum.
Apart from the fact that increased attemperation will not impair cycle efficiency, the system lends
itself to good controllability because there is inherent self regulation for changes in live steam
flow. Difficulties are sometimes experienced in maintaining the full value of live steam
temperature. This is due to the valves leaking and hence not maintaining their control range.
Partial closing of a serial manual valve is the usual stopgap solution. Superheater outlet
temperature and a derivative of superheater inlet temperature are compared to the setpoint to
form the control deviation.
(e)
Drum Level Control System
There are five 500 ton per hour and one 250 ton per hour feedwater pumps. Each boiler has a
single feedwater control valve. There is no startup valve. Drum level is controlled using a three
element controller that is drum level, feedwater flow and steam flow. The controller is electronic,
and works well. The controller setpoint is adjusted manually by the operation.
(f)
Boiler Interlock and Protection
A basic interlock system using electrical relays is in place. Protection is effected for the following
conditions: low drum level, high feedwater flow, loss of flame, two out of three induced draft
fans tripped, both forced draft fans tripped, both air heaters off, high boiler vacuum, low steam
injection pressure and low mazut pressure. Tripping the boiler will stop the coal feeders, close the
mazut valves, stop the air heaters and stop the forced draft fans. One induced draft fan will
continue to run after a trip. There is no history of missed trips, but sometimes a false trip occurs.
(g)
Burner Management System
There is no burner management system as such. However, the boilers are equipped with
photoelectric scanners. The scanner circuits are designed such that a loss of flame for three
seconds will start mazut flow to the burners. If there is still no flame after six seconds, the boiler
will trip.
5909-98C/UST.DOC/2/9/96
25
88
(h)
Emissions Monitoring
The plant has CO₂ and NO, monitors, however the NOₓ monitor is unreliable and not used. There
is also an opacity monitor in place but it does not work and is not used.
(i)
Load Control
These units are a conventional mechanical turbine governor with a centrifugal speeder gear to
vary the load setpoint. The boiler pressure controllers are used to vary the fuel flow rate to the
boiler. The pulverized coal is stored in an intermediate hopper and the transport medium from
mill to hopper and from hopper to burner is air from the air heater. There is oxygen dilution for
the transport air.
The firing system burners are positioned in the furnace sidewalls, and each sidewall has two
pulverized coal/primary air injection ports with the secondary air injection ports positioned above
and below each port. Coal must be delivered in equal amounts to each burner, even under low
loads. Coal flow is controlled by volumetric feeder speed.
Combustion control of the boilers is provided manually by the operators according to established
procedures and are based upon adjustment and testing. Excess air, the main indicator of
performance, is monitored by measuring the oxygen content of the flue gas after the superheater.
Oxygen content is displayed on the boiler control board. Additional indicators of excess air are
air-side resistance of the air heaters and air pressure after the forced draft fan. Vacuum in the
upper section of the furnace is also used as a combustion performance indicator. The original
mechanical governors are still in operation.
3.4
AIR POLLUTION CONTROLS
Emissions of particulates, sulfur dioxide (SO₂) and nitrogen oxides (NOx) and the impact of these
emissions on ambient air quality are of concern to the power plants and the surrounding
communities. At the Ust-Kamenogorsk power plant dust collection equipment is provided to
remove a major portion of the fly ash from the flue gas before discharge. Ash collection is
performed by venturi scrubbers on the boilers. The current efficiency of these units range from
96% to 97%.
From the year 1992 to 1994, the plant discharged the following amounts into the atmosphere:
Pollution Material
Ash
NOx
SO₂
Burned Fuel
Year
[t]
[t]
[t]
coal [t]
mazut [t]
1992
8,715
7,017
9,646
1,057,701
35,462
1993
7,217
7,022
9,430
1,089,972
32,759
1994
6,380
5,436
8,322
938,593
10,676
5909-98C/UST.DOC/2/9/96
26
These discharge quantities can also be expressed as follows, assuming 40% excess combustion
air:
Emission
Concentration, mg/Nm³
Ash
950
SO₂
1200
Noₓ
830
Kazakstani emission limits for new boilers are as follows:
Ash
100
SO₂
400
Nox
240
It is evident that in order to meet these limits, major investments in Air Pollultion Control
Equipment would be required.
Local limits for emission of pollutants into the environment are less stringent and it appears that
the emission limits for new boilers will not be applied to Boiler #16 at this time.
There is no NOx control equipment installed at the present time on the boilers. SO₂ reduction is
achieved by the injection of alkali irrigation water into the boiler fluegas. The plant claims that
this lowers SO₂ levels by 10 to 15%. There are no current plans to install a flue gas
desulfurization system or Nox control equipment at the plant due to lack of funds and floor space.
3.5
DISTRICT HEATING SYSTEM
General Description
The district heating hot water transmission piping system has a total installed trench length of
46.135 km. There are six major piping systems which originate from the TES-1 power plant.
The total trench length of 46.135 km is made up of the following:
5909-98C/UST.DOC/2/9/96
27
90
Transm. Piping System Designation
Trench Length [km]
TM-1
4.452
TM-2
5.27
TM-3
9.134
TM-4/1
9.445
TM-4/2
4.694
TM-5
9.62
TM-6
3.52
Total
46,135
The largest diameter of the network piping is 820 mm. The above main piping systems are
interconnected at various node points. Most of the piping is located underground in concrete
trenches except portions of the M-5 transmission piping system which are above ground. The
total maximum district water flow rate is 12500 m³/h.
In addition to the power plant as the main heat source, there is also a boiler house located on the
left bank of the Irtish River. This boiler house is also tied into the district heating network. The
boiler house is rated at 220 Gcal/h heating capacity. The boilers in this facility are coal fired. The
various boilers and their capacities are as follows:
3 steam boilers
20 t/h each
2 steam boilers
25 t/h each
4 steam boilers
50 t/h each
1 hot water boiler
50 Gacl/h
There is one pumphouse located in the piping network with district water circulating pumps in
both the supply and return lines. The pumps are constant speed pumps driven by electric motors.
In addition to the hot water transmission piping, there is a steam piping system to deliver
industrial steam to a number of customers in the vicinity of the TES-1 plant. These customers
include a machinery plant, a meat plant, two metallurgical plants, dry cleaners, water treatment
and laundry facilities, etc. There are at least three steam lines which originate from the plant,
however only one line (a 325 mm diameter pipe to the machinery plant) comes under the
jurisdiction of the district heating company which is called OBLTEPLOCOMMUNENERGY.
The total industrial steam flow rate is estimated at 200 t/h. The condensate is not returned to the
plant from any of the steam customers.
The district heating hot water transmission piping system described above also comes under the
jurisdiction of the district heating company. The district heating company interfaces with both the
plant and the local distribution companies whose function also includes local servicing inside the
buildings and the collection of the tariff for the heat and hot water energy consumption.
5909-98C/UST.DOC/2/9/96
28
al
The accounting method for heat and hot water is such that only a few larger customers pay
according to the actual heat they use. These customers have flow meters in their supply lines as
well as thermometers in supply and return lines. The heat consumption is determined from the
product of the flow rate and the supply and return temperature differential. The smaller
customers pay for heat based on the floor area of their homes. They pay for domestic hot water
based on the number of persons living in the household.
While the original design of the hot water heating system was a closed system with separate
secondary heat exchangers for space heating and domestic water generation, the current system is
of the open type with an "elevator" at the local customers. The typical arrangement of the
basement piping for h eat supply at the local customer is shown in Figure 3-2.
It should be noted that Altajencrgo has a plan to build another district heating power plant (TES-
2), which will be connected to the current district heating network. The plant would have a
nominal electric power output of 500 MW and would have five T-100 type district heating steam
turbines. The plant peak heat output capability would be 1174 Gcal/h. However, the
implementation of this plan could not proceed due to the lack of funds.
The temperature schedule of the hot water system supply and return temperatures, as well as the
temperature after mixing at the local customer's premises (after the "elevator") as a function of the
ambient outdoor temperatures is shown in Table 3-7.
5909-98C/UST.DOC/2/9/96
29
Figure 3-2
TYPICAL DISTRICT HEATING CONNECTION
(AI the Consumers House/Building)
UST- KAMENOGORSK DISTRICT HEATING SYSTEM
FOR DOMESTIC
HOT WATER NEEDS
TEMPERATURE
CHECK VALVE
CONTROL VALVE
SUPPLY LINE
250
SUPPLY LINE
Ф50
D
9
TO WALL
HEATING UNITS
1000
500
500
c
A
300
100
300
$50
200
200
RETURN LINE
ORIFICE PLATE
30
TABLE 3-7 (Continued)
UST-KAMENOGORSK DISTRICT HEATING TEMPERATURE SCHEDULE
Outside
Relative Head
DH Supply
DH Return
Temp. °C
Temp. °C
Inside Air
Temp. °C
Consumption
Temp. °C
Temp. °C
Before Heat
With Wind
Temp. °C
Exchanger
Chill
-32
0.76
113.7
53.2
72.1
118.4
12.6
-33
0.76
112.7
52.2
71.1
117.3
11.6
-34
0.76
111.7
51.2
70.1
116.3
10.6
-35
0.76
110.7
50.2
69.1
115.2
9.6
-36
0.76
109.7
49.2
68.1
114.2
8.6
-37
0.76
108.7
48.2
67.1
113.1
7.6
-38
0.76
107.7
47.2
66.1
112.1
6.6
-39
0.76
106.7
46.2
54.1
111.0
5.6
DH System Condition and Problems
The age of the piping system components in the Ust-Kamenogorsk district heating network
ranges between about 3 and 44 years. Many parts of the piping system have deteriorated due
to corrosion, and the district heating company is forced to replace a portion of the network
piping each year. The company would like to replace about 5 km (trench length) of the piping
annually however, the actual replacement is only about 2 km (trench length) per year.
The portion of the piping which is routed above ground has metal covers (jacket, either
Aluminum or Zinc). The underground piping segments which are usually routed in concrete
tunnels, have no metal jacket and the insulation is held in place by wires. The type of
insulation used is either "diatom" or "mionvata" type. The diatom type system is of Russian
manufacture, and consist of brick shaped insulating blocks plus asbestos material. The
"mionvata" insulation is similar to mineral wool based insulation system and is held in place
with wires.
For the aboveground position of piping, the age and the exposure of the joints of the metal
jacketing often results in the ingress of rainwater and moisture to the carrier pipe. This causes
both external corrosion of the bottom of the carrier pipe and sagging of the insulation within
the jacketing. For the underground pipes, the occasional partial flooding of the tunnels causes
the bottom portion of the pipes to be submerged. This also leads to the external corrosion of
the carrier pipe. The district heating company would like to have the piping replaced with the
preinsulated, bonded pipes used in most European countries. This kind of piping usually
consists of a carrier pipe with polyurathane foam insulation enclosed in a polyethylene
jacketing.
5909-98C/UST.DOC/2/9/96
32
TABLE 3-7
UST-KAMENOGORSK DISTRICT HEATING TEMPERATURE SCHEDULE
Outside
Relative Heat
DH Supply
DH Return
Temp. °C,
Temp. °C
Inside Air
Temp. °C
Consumption
Temp. °C
Temp. °C
Before Heat
With Wind
Temp. °C
Exchanger
Chill
10
0.29
70.0
46.7
54.0
70.0
27.2
9
0.30
70.0
46.3
53.7
70.0
26.5
8
0.30
70.0
46.0
53.5
70.0
25.7
7
0.31
70.0
45.5
53.2
70.0
25.0
6
0.31
70.0
45.1
52.9
70.0
24.4
5
0.32
70.0
44.7
52.6
70.0
23.7
4
0.32
70.0
44.3
52.3
70.0
23.0
3
0.33
70.0
43.8
52.0
70.0
22.3
2
0.33
70.0
43.3
51.7
70.0
21.7
1
0.34
70.0
42.9
51.4
70.0
210.
0
0.34
70.0
42.6
51.1
70.0
20.2
-1
0.36
71.4
42.9
51.8
73.9
20.0
-2
0.37
73.6
43.7
53.0
76.2
20.0
-3
0.39
75.7
44.5
54.3
78.5
20.0
-4
0.41
77.9
45.3
55.5
80.8
20.0
-5
0.42
80.0
46.1
56.7
83.0
20.0
-6
0.44
82.2
46.9
58.0
85.3
20.0
-7
0.46
84.3
47.7
59.2
87.5
20.0
-8
0.47
86.5
48.5
60.4
89.8
20.0
-9
0.49
88.6
49.3
61.6
92.0
20.0
-10
0.51
90.7
50.0
62.7
94.2
20.0
-11
0.53
92.8
50.8
63.9
96.5
20.0
-12
0.54
94.9
51.5
65.1
98.7
20.0
-13
0.56
97.0
52.3
66.3
100.9
20.0
-14
0.58
99.1
53.0
67.4
103.1
20.0
-15
0.59
101.2
53.7
68.6
105.3
20.0
-16
0.61
103.3
54.5
69.7
107.4
20.0
-17
0.63
105.4
55.2
70.9
109.6
20.0
-18
0.64
107.4
55.9
72.0
111.8
20.0
-19
0.66
109.5
56.6
73.1
114.0
20.0
-20
0.68
111.6
57.3
74.3
116.1
20.0
-21
0.69
113.6
58.0
75.4
118.3
20.0
-22
0.71
115.7
58.7
76.5
120.5
20.0
-23
0.73
117.7
59.4
77.6
122.7
20.0
-24
0.75
119.8
60.1
78.7
121.7
20.0
-25
0.76
120.7
60.2
79.1
120.7
19.6
-26
0.76
119.7
59.2
78.1
119.7
18.6
-27
0.76
118.7
58.2
77.1
118.7
17.6
-28
0.76
117.7
57.2
76.1
117.7
16.6
-29
0.76
116.7
56.2
75.1
116.7
15.6
-30
0.76
115.7
55.2
74.1
120.5
14.6
-31
0.76
114.7
54.2
73.1
119.4
13.6
5909-98C/UST.DOC/2/9/96
31
The district heating system is now an open type system as was described above. The water
loss from the system can vary from 800 m³/h with no leaks to 4500 m³/h with extensive leaks.
The normal loss used to average about 940 m³/h, however, in recent years the losses from the
system often exceed the design capability of the make-up system of 1500 m³/h. The source of
make-up water is artesian wells. Losses in excess of the design capacity of the make-up water
system leads to the corrosion of the inside surfaces of the carrier pipes. Examination of the
older piping sections by district heating company maintenance personnel indicated significant
corrosion and excessive deterioration of the piping, requiring replacement of those sections.
It was also noted that operating the system with losses in excess of the capability of the make-
up system will eventually lead to the degradation of the district heating water heat exchanger
surfaces at the power plant.
As it was pointed out earlier in Section 3 of this report, the current thermal demand exceeds
the capability of the heat sources. Therefore, because of the continued increase of the heat
demand, new transmission lines with larger diameters should be developed, on at least critical
positions of certain existing transmission pipe sections should be replaced with larger diameter
piping when these sections exhausted their useful lives.
The district heating piping system uses three different kinds of expansion devices (loop type,
watertight gland type, and bellows type) and the DH company reported no problems with any
of them.
The problem with the industrial steam pipe is that it was not specifically designed for steam
service, it was originally a 325 mm diameter water line. It is carrying steam with a
temperature twice the original design. The carrier pipe is enclosed in 120° segments of
preformed asbestos based insulation held in place by wires. The line is running underground
in a trench and the DH company would like to replace the pipe and route it aboveground.
The DH water circulating pumps which are located in the system network boost the pressure
both in the supply and return lines. The DH company reported no special problems with the
pumps even though they are of 1970 vintage and are approaching the end of their design lives.
However, there are no automatic means of controlling flow or pressure, the pumps are driven
by constant speed motors.
The transmission piping network is characterized by a number of ring connections, which cross
each other at various "Node points". This allows a relatively high security of heat supply. In
addition there are other node points or connecting points at which the piping systems of the
various distribution systems are connected to the main transmission headers. However, there
is a lack of instrumentation and control of flow and isolation capability at these node points,
and there is a very minimal number of instrumentation and automatic control at the pumphouse
and the dispatch center. Those that are available are quite old, either needing repair or re-
5909-98C/UST.DOC/2/9/96
33
is
calibration. Without instruments which function properly to monitor and record such essential
variables as flow rate, temperature, and pressure, it is difficult to accurately determine balance
measurements and conduct effective energy-efficient operation.
The District Heating company would also like to relocate the dispatch center. The new
location would be adjacent to the pumphouse. This location is essentially toward the center of
the expanding system. The new dispatch center will require computers and instrumentation
(SCADA) system to monitor and control the dispatch of the transmission system and better be
able to interface with the heat sources and heat consumers connected to the transmission
system.
5909-98C/UST.DOC/2/9/96
34
91
4.0
STATION RECOMMENDATIONS
4.1
ENERGY SUPPLY AND DEMAND SITUATION
As discussed in the previous sections, the major problem with the Ust-Kamenogorsk plant is that
the present and projected demand for electric power and heat exceeds the capability of the plant.
A contributing factor to the magnitude of this problem is the age and accumulated operating
hours of the equipment. It must be recognized that a number of turbines and auxiliaries are at/or
near the end of their service lives as described in the previous sections. As the units are retired,
the electric power and heat generation capacity of the plant will decrease accordingly. For this
reason, the overall capacity of the plant verses current and projected loads were assessed. This
load assessment is then used as a basis for specific recommendations for completing the
installation of line No. 7 (turbine No. 12 and boiler No. 16) and auxiliaries to alleviate or at least
minimize present and future shortfalls in plant production capacity as compared with electric and
heat demands.
During the Burns and Roe visit at the power plant, plant management indicated that there is a
deficit in capacity of about 30%. Therefore, the utility would prefer adding new capacity. Burns
and Roe's experience with other district heating plants in the former Soviet Union countries
indicated there is a reluctancy of shutting down part of a plant for significant refurbishment of
individual units, before additional capacity can be built. This is especially true for the CHP plants
which are providing energy to customers whose peak demand is greater than the output capability
of the plant. Ust-Kamenogorsk is one such plant.
It was also observed that the electrical output of the plant is decreased during the summer months
to about half (119.5 MW). The loss of capability of 122 MW was due to the following
limitations:
Cooling Water Shortage
:
77 MW (units with condensers)
Thermal Output Reduction
:
40 MW (on backpressure turbines)
Turbine Flow Path Degradation
:
5 MW (Unit 8)
While no detailed future load forecasts have been prepared by Burns and Roe, the plant personnel
provided the following projected energy demands on the Ust-Kamenogorsk facility for the next 10
years:
5909-98C/UST.DOC/2/9/96
35
98
ELECTRIC POWER
THERMAL ENERGY
DEMAND
DEMAND
YEAR
(Million kWh)
(Thousand Gcal)
1995
1200
3150
1996
1200
3175
1997
1225
3215
1998
1225
3315
1999
1250
3425
2000
1300
3550
2001
1350
3690
2002
1420
3830
2003
1480
3970
2004
1540
4110
2005
1600
4250
From a review of the above data, it can be seen that over the next five years, the electric power
demand on the plant is projected to increase by 8.3%, and the district heating load by 12.7%.
Over the next 10 years, the electric power demand on the plant is projected to increase by 33.3%.
and the district heating load by 34.9%.
The above data was compared to the actual electrical and thermal energy generation in the
previous years. The operating data received from the plant indicates the following actual energy
production levels.
Electric Energy Production
Thermal Energy Production
YEAR
[10⁶ kWh]
[10³ Gcal]
1993
1075.9
3132.5
1994
925.1
2805.5
Therefore it can be seen that the 1995 electrical energy demand is about 29.7% greater than the
1994 actual generation, and the 1995 thermal energy demand is about 12.3% greater than the
previous year generation. While these large differences are partially due to the 1994 fuel
shortages, even if we consider the 1993 actual generating levels as representative values for the
plant, the difference in electrical energy production and thermal energy production by the year
2000 will be 20.8% and 13.3%, respectively. Similarly by the next 10 years these differences will
grow to 48.7% and 35.7%. This evaluation of course does not consider the retirement and
remaining life of the existing units discussed in the previous subsection. When these factors are
considered, electrical generation deficits of up to 42% and 78% may be expected by the year 2000
and 2005, respectively.
5909-98C/UST.DOC/2/9/96
36
On the thermal energy supply side, it was noted by plant personnel that the plant has a thermal
load deficit of about 30%. This plant mostly runs "wide open" and the temperature of the district
heating supply water is lower than design. This means that the level of comfort inside of buildings
is severely reduced during colder ambient conditions.
In order to substantiate the magnitude of the above deficit, the plant data provided for the
installed and available capacities of industrial steam and hot water loads was reviewed. The
installed total thermal capacity as of the end of 1994 is 1050.9 Gcal/h. The 596 Gcal/h of this
figure is to be provided by the steam turbines, and the balance, or 454.9 Gcal/h, comes from
pressure reducing units. The usable heating capacity of the system is obtained by reducing the
installed capacity by certain limitations due to equipment conditions. The actual thermal output
capacity is determined from the usable capacity after subtracting certain losses and the plant's own
heating needs.
Plant data indicates that the installed heating capacity at the plant is reduced by 107 Gcal/h
because of the overheating of the boiler superheater tubes. The available heating capacity would
also be 20 Gcal/h lower than installed because of the problem mentioned previously with the No.
8 steam turbine (breakage of the 20th and 21st stage blades). However, some of this loss can be
recovered by taking more steam from the pressure reducer due to the reduction of load on the
No. 8 turbogenerator. The resulting total equipment limitation is 102.5 Gcal/h.
The station's own needs in the form of steam is 10.4 Gcal/h and the heating needs and losses in
the form of hot water are 89 and 48.9 Gcal/h, respectively. The installed thermal capacity in the
form of steam is 200 Gcal/h and in the form of hot water is 850.9 Gcal/h. Therefore, with the
above values, the thermal output capabilities of the Ust-Kamenogorsk plant are as shown in Table
3-4.
TABLE 3-4
THERMAL OUTPUT CAPABILITIES OF THE U-K PLANT
Installed total heating capacity
1050.9 Gcal/h
In the form of steam:
200. Gcal/h
In the form of hot water:
850.9 Gcal/h
Limitation due to equipment conditions:
102.5 Gcal/h
Usable Thermal Capacity:
948.4 Gcal/h
Station's own needs and losses
In the form of steam:
10.4 Gcal/h
In the form of hot water:
137.9 Gcal/h
Total:
148.3 Gcal/h
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100
Actual output capacity
Total:
800.1 Gcal/h
In the form of steam:
189.6 Gcal/h
In the form of hot water
610.5 Gcal/h
From the above table it can be seen that the maximum load that can be satisfied in the form of hot
water, i.e. the district heating load is 610.5 Gcal/h. The operating data obtained from the plant
indicates that during 1994 the maximum hot water heat load occurred on January 15, 1994 and its
value was 659.3 Gcal/h. However during that day the ambient temperature was only -20°C, and
the hot water supply temperature was only 95°C instead of 110°C as would be required under
such conditions. When the heat load is transferred to the rated ambient temperature of the Ust-
Kamenogorsk DH system the corresponding maximum heat load that the plant must satisfy is
856.1 Gcal/h. Therefore the current (1994) deficit in hot water heating load capability is:
856.1 - 610.5 X 100 = 28.7%
856.1
Since the industrial steam load during that time was 118 Gcal/h, the total thermal load required
for the plant was 974.1 Gcal/h. This figure is 17.8% higher than the 800.1 Gcal/h of total actual
load that the plant can currently provide.
Looking at the energy need projection data provided by the plant above and assuming that the
peak load after 1994 will increase proportionally with the increase in total annual load, the peak
heat energy loads can be estimated accordingly as:
Year 1995 - 1094 Gcal/h
Year 2000 - 1233 Gcal/h
Year 2005 - 1476 Gcal/h
Without going into detailed load deficit calculations it can be seen that the current 28.7% gap
between the peak thermal loads of the area served by the plant and the available thermal output
capability will significantly widen as the older units are retired from service. For instance, if
turbines No. 4 through 8 were forced into retirement by the year 2000, the resulting loss of
energy supply from the extractions and turbine exhausts would be 344 Gcal/h as follows:
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101
Turbine No. 4
33 Gcal/h
Turbine No. 5
33 Gcal/h
Turbine No. 6
83 Gcal/h
Turbine No. 7
83 Gcal/h
Turbine No. 8
112 Gcal/h
TOTAL
344 Gcal/h
Therefore the peak capacity deficit in that year could be 1233 - (610.5-344) = 966.5 Gcal/h.
It is clear from the above discussions of capacity and age of the equipment and the projections of
future demand, that installation of additional plant capacity is required as soon as possible to meet
electric power and industrial steam and district heating demands. One recommended solution,
which could significantly alleviate this problem, would be to add additional electric power and
heat generation capabilities by installing turbine No. 12 and boiler No. 16 (Line No. 7). This may
be a very cost effective solution, since the turbine has already been purchased and its pedestal and
condenser are already installed.
Conclusions
The results of the assessment made above of capacity versus demand in the future years lead to
the following conclusions.
If the turbine No. 12 and boiler No. 16 installation is not completed, annual
electric consumption will likely begin to exceed supply capability of the plant
before the year 2000.
If Line No. 7 is installed in the near future, the deficit in plant peak capacity for
district heating and industrial steam will be reduced considerably.
The plant personnel have made a decision to add additional electric power, district heating and
industrial steam capacity to the Ust-Kamenogorsk Plant. This decision was followed up by
installation of the turbine pedestal, installation of the condenser, and purchase of the turbine for a
new Unit No. 12. This work was stopped due to lack of funds.
Based on our assessment of the age, accumulated operating hours, the condition of the
equipment, production capability versus demand for the Ust-Kamenogorsk turbines, Burns and
Roe concurs with the decision of plant personnel, and recommends installation of turbine No. 12,
boiler No. 16 and auxiliaries. The installation of this turbine will add a nominal 80 MW (100
MW maximum) electric output capability and about 170 Gcal/h thermal load capability to the
existing plant capacity.
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102
It is recommended that the installation of Line No. 7 and auxiliaries be completed as soon as
possible. Since this work has already been partially completed, it appears to be a cost effective
first step in refurbishment of Ust-Kamenogorsk Plant. Once this step is accomplished, the plant
can better afford to shut down existing turbines for refurbishment and for retirement of older
smaller units.
4.2
STEAM BOILERS
Boiler No. 16 Design Parameters
The new boiler No. 16 is manufactured by the Barnaul Boiler Company. This boiler is type BKZ-
420-13.8-560. The boiler is of the drum type with natural circulation, a conventional two-pass
configuration with a short horizontal, and a vertical rear convection pass. The radiant balanced
draft furnace tubewalls are fully water cooled, 60 mm dia. X 5.5 mm thick carbon steel tubes on
64 mm centers, with refractory backing, insulation and casing. The furnace dimensions are 7700
mm deep by 14,460 mm wide. The furnace has a coutant type tube hopper formed by the front
and rear walls with a 50° angles to the horizontal. The superheater stages can be subdivided into
radiant, radiant-convective and convective types. The following table shows the design
parameters of the new boiler.
TABLE 4-1
Boiler #16 Design Thermal Performance Parameters
Parameter
Units
Design
Live steam flow
te/h
420
Live steam pressure
MPa abs. (at. abs.)
13.8 (140)
Superheated steam temperature
°C
560
Feedwater temperature to economizer
°C
230
Airheater exit fluegas temperature
°C
160
Combustion air temperature to burners
°C
330
Excess air in fluegas @furance exit
%
20
Excess air in fluegas leaving airheater
%
40
Boiler efficiency LHV basis
%
91.0
The boiler is designed to fire bituminous coal, with an "as fired" volatile matter minimum of 36%.
The design coal source will be the Shubarkul mine, Kazakstan.
The three stage superheater is of the pendant non-drainable type and has steam-side crossovers
and two stages of spray type desuperheaters. Spraywater is generated from condensed saturated
steam in a heat exchanger using feedwater from the first stage economizer water outlet as the
cooling medium. The horizontal drainable two-stage economizer has bare tubes in a staggered
5909-98C/UST.DOC/2/9/96
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103
arrangement with water in upflow and fluegas in downflow. The three-stage airheater is the
tubular type with fluegas in the tubes in downflow and combustion air over the tubes in
upflow/crossflow. The economizer and airheater tubebank stages are located in the rear vertical
convective pass.
The furnace has a dry bottom ash disposal system. The furnace, the short horizontal and the top
portion of the rear vertical convective pass are top supported allowing for cubic thermal
expansion. The lower portion of the rear convection pass is bottom supported, with a metal
expansion joint to compensate for the downward/upward thermal expansion. The expansion joint
is installed between the last stage of the tubular airheater and second stage economizer.
The indirect (pulverized coal storage) coal firing system consists of two subatmospheric pressure
ball mills, model SBM320/570. Each mill has an external static classifier and separating cyclone.
The boiler has a single common pulverized coal storage bin with eight PC feeders. The coal
drying medium is a mixture of (1) hot fluegas, taken from the furnace frontwall above the lower
furnace horizontal exit plane by two high temperature fluegas ducts of stainless steel construction
and discharging into each ball mill raw coal inlet side and (2) hot primary air taken from the final
stage tubular airheater. The mixture maximum oxygen content is limited to 16% by volume and
the static centrifugal classifier exit mixture temperature is controlled at a maximum of 130°C. The
boiler has two drying medium mixture/PC conduit systems, two mill fans which are combined
exhaust/conveying fans for conveying the pulverized coal from the PC storage bin to the burners
with a high concentration of pulverized coal. The boiler furnace has a total of twelve horizontal
pulverized coal burners, eight swirl type burners located on the frontwall of the furnace in two
lateral rows of four, plus four vent burners in the furnace sidewalls, in two lateral rows of two.
Four overfire air nozzles are located in the furnace rear wall for the bulk staging of combustion air
in two lateral rows of two nozzles. Each swirl type pulverized coal burner has a steam atomized
mazut gun for start-up and combustion stabilization.
The draft plant of the boiler consists of two FD and ID fans. Hot air recirculation from the final
stage airheater air outlet into the FD fan suction side is used as tubular airheater cold end low
temperature corrosion protection. All fans of the boiler are radial flow centrifugal type with
electric motor drive. Due to the low slagging propensity of the Shubarkul coal mineral matter,
there are no furnace tubewall blowers installed. Retractable sootlances are not provided for the
cleaning of the pendant radiant/convective and convective superheater stages. A shot-type
heating surface cleaning system is installed in the rear convective pass, for the economizer and
tubular airheater tubebanks. Particulate emission control equipment consists of four venturi wet
scrubbers per boiler, designed by the R&D department of Kazakstanenergo and having a design
collection efficiency of 99.4%. No equipment is provided for fluegas desulfurization.
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4.3
STEAM TURBINE GENERATORS AND AUXILIARIES
Turbine No. 12 Design
Information on the No. 12 steam turbine was requested from the plant. This information indicates
that the unit has both industrial steam extraction and district heating steam extractions. The
turbine's main steam parameters match the steam parameters of the high pressure steam supply
header currently installed in the plant. The turbines nominal electric output is 80 MW. The
nominal thermal output steam flows and other relevant performance parameters are shown in
TABLE 4-2. The values shown in this table are based on circulating water flow of 8000 m³/h
entering the turbine steam condenser at an inlet temperature of 20°C.
TABLE 4-2
TECHNICAL CHARACTERISTICS OF THE NO. 12 STEAM TURBINE
Type
PT-80/100-130/13
Nominal Output, MW
80
Main Steam Pressure, kg/cm²(a)
130
Main Steam Temperature, °C
555
Nominal Industrial Extraction Steam Flow, t/h
185
Nominal District Heating Steam Extraction Flow, t/h
132
Main Steam Flow at Nominal Conditions, t/h
440
Maximum Main Steam Flow, t/h
470
Final Feedwater Temperature in Pure Condensing Mode, °C
230
Specific Heat Consumption in Pure condensing Mode at
2290
Nominal Output, kcal/kWh
Regenerative Extraction Configuration
3HPH+D+4LPH
District Heating Stages
2 (1 LP + 1 HP)
Nominal Industrial Steam Extraction Pressure, kg/cm²(a)
13
Rotational Speed, RPM
3000
Turbine Manufacturer
LMZ
Generator Model
TVF-110-2EVZ
Turbine No. 12 is a tandem-compound, non-reheat, regenerative, district heating turbine with a
condensing tail manufactured by the Leningrad Turbine Plant (LMZ). The turbine is a two
cylinder machine with a separate high pressure (HP) section and the low pressure (LP) cylinder.
However, the LP cylinder consists of an IP and a LP section. It is designed to receive steam at
130 ata, 555°F throttle conditions. Figure 4-1 schematically illustrates the steam turbine and its
auxiliary cycle components.
As can be seen from the figure the industrial steam extraction is provided from the HP turbine
section exhaust at a pressure of 13 ata which is sufficient to supply the plant's existing industrial
5909-98C/UST.DOC/2/9/96
42
steam supply header at 7 ata. Water for district heating is heated in two stages, each of which
receives heating steam from separate extractions of the IP turbine section.
The pressure is controlled at the industrial steam extraction at the nominal value of 13 ata until the
steam flow entering the IP section of the LP cylinder is below 221.5 t/h. When this steam flow
rate is increased above this value, the industrial steam extraction pressure will increase up to 16
ata. The pressure in the industrial extraction can be varied at 13 ± 3 ata.
The nominal value of the district heating steam pressure in the upper DH extraction is 1.2 ata with
two-stage district water heating. However, depending on heating load conditions, the pressure in
the upper district heating extraction can be varied between 0.5 and 2.5 ata with two-stage district
heating, and the pressure in the lower district heating extraction can be varied between 0.3 and
1.0 ata with single-stage district heating operation.
In addition to industrial and district heating extractions the turbine has regenerative feedwater
heating extractions for 3 high pressure heaters, 4 low pressure heaters and a deaerator which
operates at a pressure of 6 ata. Deaerator piping steam is provided from the exhaust of the HP
turbine section. The district heating water heat exchangers both are provided with drain pumps
which return condensate to the main feedwater cycle. Drains from the lower DH heat exchanger
are pumped forward to the inlet of the No. 3 LP feedwater heater and the drains from the upper
DH heat exchanger are returned to the No. 4 LP feedwater heater. The condensate return from
the industrial steam supply is at a temperature of 100°C and is assumed to be returned to the
feedwater system upstream of LP feedwater heater No. 3.
The turbine can be operated either in the pure condensing mode or the heating mode. In the
heating regime the maximum electrical, industrial steam, and district heating outputs of the turbine
are interdependent. For example, at a given main steam flow the greater rate of industrial steam
and district heat production, the lower the maximum electric power generating capability. In
order to track the performance of the steam turbine and to be able to determine the required main
steam flows under different heat and electric load conditions, various regime diagrams have been
developed by turbine manufacturers. One such diagram showing the performance characteristics
of the No. 12 turbine operating with industrial steam and both district heating extractions (2 stage
DH operation) is shown in Figure 4-2 for illustrative purposes. For example, assuming a district
heating water return temperature of 52°C, the following generation capability values can be
determined:
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106
Figure 4-1
TURBINE NO. 12 AND AUXILIARIES
UST- KAMENOGORSK TGS PLANT
P₀ =13Mpa(130kgcm2 ); To =555°C
INDUSTRIAL
25
27
19
EXTRACTION
C
TO BOILER
30
FROM DEAERATOR
H.P. HEATER #7
INDUSTRIAL
H.P. HEATER #6
EXTRACTION
CONDENSATE
RETURN
H.P. HEATER #5
TO LOW POINTS
TANK
TO CONDENSER
RECIRCULATION
τz
L.P. HEATER #1
DEAERATOR
I
L.P. HEATER #4
L.P. HEATER #3
DISTRICT HEATING
L.P. HEATER #2
HEAT EXCHANGERS
44
At an electric power generation rate of 80 MW, and an output of 80 Gcal/h to the district
heating system, the maximum rate of industrial steam production which could be achieved
is 90 Gcal/h. This operation represents a total of 170 Gcal/h production for industrial
steam and district heating.
At an electric power generation rate of 70 MW, and an output of 70 Gcal/h to the district
heating system, the maximum rate of industrial steam production which could be achieved
is 75 Gcal/h. This operation represents a total of 145 Gcal/h production for industrial
steam and district heating.
At an electric power generation rate of 80 MW, and an output of 95 Gcal/h to the district
heating system, the maximum rate of industrial steam production of which could be
achieved is 60 Gcal/h. This point of operation represents a total of 155 Gcal/h production
for industrial steam and district heating.
As can be seen from the previous paragraph many load combinations of operating modes or
regimes are possible. Some of these are usually guaranteed by the turbine manufacturer. The
guaranteed performance figures in terms of specific steam rate (in heating regimes) and in terms
of turbine heat rate (pure condensing regime) for five regimes are shown in Table 4-3. It should
be noted that in this table the industrial extractions are given in terms of steam flow (t/hour)
whereas the district heating extractions are given in terms of Gcal/h.
It should be noted that diagrams similar to the regime diagrams in construction have also been
developed to show the specific heat consumption of the turbine under various electrical and
heating load combinations. The specific heat consumption (or heat input changeable to power,
measured in kcal/kWh) is analognons to the turbine heat rate (which is only defined in pure
condensing modes), and for the No. 12 steam turbine it ranges between 1400 and 2600 kcal/kWh.
5909-98C/UST.DOC/2/9/96
45
Figure 4-2
TURBINE NO. 12 REGIME DIAGRAM
Go MORE = 470т/ч.
T/HOUR
Go
150
120
400
06
200
100
106
121
091
Guca 3807/4
140
60
area of natural
pressure increase
300
in industrial
extraction
200
120
NT
30
40
50
60
70
80
90
100 M&T[MW]
0
Γ0
40
120
150
60
60
80
GCAL/HOUR
QT
CONDITIONS:
P,=13Mpa(30kgtm²);T,=55°C Pₙ = 1,3Mpa(13kgtm² );
LEGEND:
Рп = industrial steam extraction pressure
Рвто=иррег extraction pressure for dist heating
P₂ = condenser pressure
G₄cA=steam flow into I.P. section
flow
Go =main steam flow
46
109
TABLE 4-3
GUARANTEED PERFORMANCE OF THE PT-80/100-130/13 TURBINE
Regime, No.
Turbine
Industrial steam extraction
District heating extraction
District
Generator
Feed water
Guaranteed
Output, MW
water return
Efficiency,
temperature °C
specific steam
temperature,
%
flow kg/kWh
°C
pressure,
steam flow,
pressure *
Heat flow,
kg/sm²(a)
t/h
kg/sm²(a)
Gcal/h
1
80
13
185
0.9
68
42
98.6
249
5.5
2
80
13
250
-
-
-
98.6
249
6.06
3
80
16
40
1.4
100
42
98.6
239
4.7
4
100
16
95
2.5
36
70
98.6
250
4.75
5**
80
-
-
-
-
-
98.6
230
heat rate
2290
kcal/kWh
*Pressure shown is in the upper (2nd stage) DH extraction
**Pure condensing mode
5909-98C/UST DOC/2/9/96
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Turbine Auxiliaries
The following is a brief description of the turbine No. 12 auxiliaries:
The condenser is a two pass design, type 80 KCS-1 with a total surface area of 3000m². The
condenser requires a cooling water flow of 8000 m³/h. Of the 3000 m² total tube surface area,
765 m² is the surface area of a built-in tube bank which can be used for district heating
makeup water heating.
Of the 4 LP feedwater heaters, the lowest pressure heater HTR. No. 1 is a horizontal heater
and is located inside the condenser neck. LP heater No. 2 is a vertical heater, type PN-130-
16-10-2. LP feedwater heaters No. 3 and 4 are both type PN-200-16-7-1.
Of the 3 high pressure feedwater heaters, HP heaters No. 5 and No. 6 are type PV-425-230-
23-1 and PV-425-230-35-1, whereas the highest pressure heater (FW HTR No. 7) is a vertical
type PV-500-230-50-1.
There is one 6 ata deaerating heater with storage tank provided for the No. 12 turbine.
There are two district heating water heat exchangers provided (upper and lower stage), each
with a tube surface area of 1300 m². They are type PCG-1300-3-8-10 heaters and are
designed for a maximum flow rate of 2300 m²/h.
There are 3 condensate pumps type KC-80-155. The operating number of pumps depends on
the steam flow into the condenser. The pumps are driven by 75 kW electric motors.
There are two three-stage steam jet air ejectors for the condenser. They are type EP-3-701
ejectors. The condenser has one operating and one spare ejector. In addition, there is one
EPI-1100-I type start-up ejector.
There are 2 feedwater pumps provided with approximate flow rates of 320 m³/h and 160
meter atmosphere head. They will be driven by electric motors.
In addition to the above mentioned pumps there will be various drain pumps, DH water
booster pumps and condenser circulating water pumps. The DH water heat exchangers each
will have two type KN-KC-80-155 drain pumps, driven by 75 kW electric motors each. There
will be two DH water booster pumps. The first stage pump will be type SE-5000-70-6 type
driven by 500 kW electric motor, and the second stage pump will be type SE-5000-160 with
an 1600 kW electric motor.
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48
The condenser circulating water pumps are type 24NDN driven by 500 kW motors. There are
2 pumps each sized for a flow rate of 5000 m³/h and a total head of 26m.
The electric generator for the turbine is type TVF-110-2 manufactured by the Electrosila
company. The rotor is hydrogen cooled and the generator stator is water cooled.
In addition to the above equipment various piping systems will have to be installed together with
valves and instrumentation and controls.
As it was noted earlier the turbine has already been procured by the plant and the turbine pedestal
has been erected and the condenser installed. While foundations for other main components in the
turbine room have also been provided, further construction and equipment procurement have been
halted due to a lack of funds. Thus the plant already prepared a plan for the installation of the
various components including a new boiler (No. 16) as noted in earlier sections.
It was noted earlier that in 1994 the electric capacity of the plant is severely curtained during the
summer months, by 122 MW. About 63% of this figure is due to inadequate cooling water
supply from the River. Therefore, the plant has embarked on a plan to build cooling towers as
part of the plan to complete new line No. 7. Since the existing plant already has a shortage in
cooling water supply, the operation of the new No. 12 turbine will certainly require the use of a
new cooling tower. Therefore, cost allowance for at least one cooling tower must be made.
It is also recommended that the plant improve its NDE capabilities of existing units by purchasing
additional boroscopes and replication type creep testing equipment. This will help the plant to
predict metal degradation and to detect minor cracks in thick walled pressure parts of the
turbines, boiler, and main steam piping without resorting to the more costly and sometimes not
readily available outside laboratories.
4.4
INSTRUMENTATION AND CONTROLS
Since a new line number 7 will be installed, consisting of boiler number 16 and turbine Number
12, a standard instrumentation and controls system will be installed. The items below are new
instruments for the environmental monitoring, and improved instruments for boiler control. The
following plant instrumentation and control improvements are recommended based on discussions
with cognizant plant engineering management.
NO, monitoring equipment for the #16 boiler to determine the effectiveness of NOx
reduction initiatives.
SO₂ monitoring equipment to determine the effectiveness of SO₂ reduction.
CO monitoring equipment to fine tune number 16 boiler for optimum efficiency.
5909-98C/UST.DOC/2/9/96
49
v/z
Instruments for analyzing particulate content in flue gas to monitor the environmental
performance of boiler number 16.
Flue gas flow monitoring equipment to determine mass release rates of pollutants from
boiler number 16.
In situ, high temperature O₂ monitoring equipment at number 16 boiler outlet to adjust
boiler parameters for optimum efficiency.
Sodium monitor for superheated steam to determine efficiency of boiler blowdown
system.
Oxygen monitor for feedwater for improved control of feedwater chemistry.
Coal flow monitor for mills to determine if improvements in efficiency are reflected in
decreased fuel consumption.
Portable combustion analyzer with peripherals to adjust boiler number 16 parameters and
determine optimum location for stationary instruments.
Heat spy to quickly determine heat leakage points from number 16 boiler, number 12
turbine and isolate "Hot Spots" in electrical equipment.
The above list was developed during the condition assessment of the plant and is considered
necessary for modernization. Installation of this instrumentation will extend the plant life and
yield an improvement in reliability and availability and reduce maintenance costs.
4.5
AIR POLLUTION CONTROLS
The Ust-Kamenogorsk TES was engineered and constructed with due consideration of the
environmental laws and regulations in place at the time of construction. Accordingly, particulate
removal systems were installed on the boilers.
In recent years, further consideration has been given to the environment. New legislation has
been enacted and new regulations have been implemented which have imposed more stringent
requirements for pollution control. This will require the particulate removal system to be more
efficient.
As was stated in section 4.1, low NO, burners with overfire air nozzles will be installed on boiler
No. 16. In addition, four wet venturi scrubbers will be used on the boilers to collect fly ash. The
design collection efficiency of these scrubbers will be 99.3% according to the manufacturer.
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113
These high efficiency scrubbers apparently utilize emulsifying agents to improve ash collection.
This improvement in efficiency will reduce ash emissions to about 200 mg/Nm³.
Installation of SO₂ reduction equipment has not been considered. SO₂ removal efficiency is
expected to increase from the present level with the installation of the improved dust collection
scrubbers but the extent of the improvement has not been quantified.
4.6
DISTRICT HEATING SYSTEM
Based on the information obtained during our plant visit and discussion with management
personnel, the following are our recommendations regarding the rehabilitation of the DH
transmission system:
Replace 3.059 km (trench length) of the TM-1 piping
Replace 0.713 km (trench length) of the TM-2 piping
Replace 4.035 km (trench length) of the TM-3 piping
Replace 5.224 km (trench length) of the TM-4/1 piping
Replace 0.089 km (trench length) of the TM-4/2 piping
Replace 6.371 km (trench length) of the TM-5 piping
Replace 3 km length of industrial steam piping
Install variable speed pump drives at the plant and the booster stations.
Install motor operated isolation valves to divert flow between various transmission
line sections and to be able to quickly isolate transmission and/or distribution
branches for maintenance.
Install instrumentation (flow meters, pressure and temperature transmitters) at the
transmission system node points.
Furnish new instrumentation and controls in the pumphouse for the district heating
water circulating water pumps.
Relocate the dispatch center to the area adjacent to the circulating water
pumphouse. Equip the center with a modern SCADA system to monitor and
control the operation of the entire DH system and to interface with the power
plant, boiler house, and the distribution system.
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4.7
REHABILITATION BENEFITS
The table below summarizes the anticipated benefits of implementing the installation of new line
No. 7 described in Sections 4.1 to 4.6.
REHABILITATION BENEFITS
CHARACTERISTIC
BEFORE
AFTER
% IMPROVEMENT
Plant Main Steam Flow,
1,650
2,070
25.4
t/h
Plant Output, MWe
241.5
321.5
33.1
Plant Heat Output Gcal/h
1050.9
1220.9
16.1
Benefits will also be realized from the Instruments and Control System modifications for boiler
No. 16 and emission monitoring system. The implementation of these recommendations will
improve the general operation of the plant by increasing its availability and reliability, decreasing
Operating and Maintenance costs, and extending the life of the units. The implementation of air
pollution control recommendations will help improve the air quality (environment) in the vicinity
of the plant. The Low NO, burners will lower the NOx discharge from the plant and should allow
the plant to meet future environmental pollution limits. In addition, the new venturi scrubbers will
greatly reduce the amount of particulates that are expelled into the atmosphere from boiler No.
16.
The installation of the new line No. 7 will also result in reducing the potential cost of replacement
power to be purchased if the other units of the plant were to be shutdown due to unplanned
(forced) outages. As was stated in Section 4.1, the installation of the new line will also help
reduce the deficit of heat capacity. The new turbine (No. 12) will increase the heat output of the
plant by 16.1%. This addition will increase the comfort level of the population of Ust by the
improved District Heating System.
The district heating system improvements will result in the following benefits.
The district heating piping network rehabilitation will result in substantial reduction
in heat and water losses due to improved piping and insulation of the system. It
will minimize the external corrosion of the piping system and extend the piping life
by at least 15 years.
The installation of variable speed pump drives will reduce electric power
consumption significantly resulting in substantial cost savings.
5909-98C/UST.DOC/2/9/96
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The installation of automatic control system (SCADA) will improve the district
heating system operation by providing automatic control, regulation and
monitoring of system parameters which will result in energy efficient operation and
substantial cost savings.
Installation of flowmeters and pressure and temperature transmitters at the
transmission system node points will balance the system load which will reduce
energy waste by making the district heating system more responsive to the changes
in heat demand in the various sections of the system. With a more responsive
district heating system, end users will not need to open windows to control the
comfort level. It will be controlled by the SCADA system.
In addition, the Ust Kamenogorsk plant management had requested to increase the
capacity of the following systems to meet the increased demand and to improve the
environment.
a) Increase the capacity of boiler feedwater makeup system from 300 t/h to
500 t/h to meet the increased makeup water demand due to addition of
boiler No. 16.
b) Increase the capacity of district heating makeup water system from the
present level to 4000 t/h to meet the increased demand.
c) Procure and commission a wastewater treatment system with a capacity of
120 t/h.
Burns and Roe did not have the opportunity to evaluate the above mentioned request for the
systems expansion because the requests were made after the site visit. These system. expansion
needs should be verified during the future investigations. However, we have included funds in our
cost estimates for these systems expansion.
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116
5.0
CAPITAL COST ESTIMATES
Cost estimates for the various rehabilitation items have been developed based on Burns and Roe
inhouse estimates for similar size jobs or from vendor estimates. The estimates are based on the
following scope of supply and are expressed in 1995 U.S. dollars.
Scope of Supply
Drum type natural circulation boiler (Boiler No. 16)
Two ball mills with electric motor drives
Two volumetric raw coal feeders
Two static, centrifugal mill classifiers
Two separating cyclones
Pulverized coal storage bin with screw conveyor and eight PC feeders
Two mill circuit ducting systems, including pulverized coal conduits, storage bin to burners
Two hot fluegas ducts from the furnace frontwall, above the horizontal furnace exit plane, to
the ball mills raw coal inlets, with supports
Eight burners, swirl type with mazut guns
Four vent burners
Four overfire air nozzles
Ducts, FD fans to airheaters, airheaters to burners
Flues, tubular airheater exit to venturi wet scrubbers, scrubbers to ID fans, ID fans to stack
Tubular airheater, three-stage
Two hot air recirculation duct systems to FD fans suction side
Two FD fans with electric Motors
Two mill exhaust/pc and fluegas conveying fans
Four wet venturi scrubbers
Boiler suspension structural steel
Platforms, stairs and handrails
Two raw coal silos
Safety valves with silencers
Bottom Ash Removal System for Boiler No. 16
Feedwater stop and check valves
Miscellaneous vent and drain valves
Boiler refractory, insulation and casing
Insulation and lagging for ducts and flues
Burner management and flame safety systems
Drag chain conveyor for furnace bottom ash removal
Live steam attemperators with valves
Electrical generator and exciter
Three high pressure feedwater heaters
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54
117
One deaerator storage tank
Four low pressure feedwater heaters
Two boiler feed pumps and motors
Three condensate pumps and motors
Two feedwater heater drain pumps
Main steam piping from 130 atm header to steam turbine No. 12
Condensate and feedwater piping for turbine No. 12
Extraction steam piping with extraction check and motor operated isolation valves
Heater Drain piping
Two DH water heat exchangers
Four DH heat exchanger drain pumps
Two DH water circulating (booster) pumps
DH water piping between the DH heat exchangers and the tie-in point to the existing DH
transmission piping
One gland steam condenser
Condenser Air Removal System (Air Ejectors)
Two circulating water pumps
Circulating water piping between cooling tower and condenser
One cooling tower for turbine No. 12 heat sink
One step-up transformer
One auxiliary transformer
Boroscopes (NDE)
Replication type creep testing equipment (NDE)
Emission Monitoring Equipment
Boiler Monitoring Equipment
New Turbine Governing System
Miscellaneous Instruments and Controls
Replacement of Damaged District Heating piping per Section 4.6
Installation of variable speed pump drives
Installation of motor operated isolation valves and flowmeters and pressure and temperature
transmitters on DH piping sections
Installation of DH Instrumentation and Controls including SCADA System
Procurement and Commissioning of District Heating makeup water plant with a capacity of
4000 t/h
Additional Makeup Water Treatment (Demineralizer) Plant (200 t/h capacity)
Procurement and commissioning of Wastewater treatment plant with a capacity of 120 t/h
Procurement and Commissioning of New Coal Handling System including Railcar dumper
5909-98C/UST.DOC/2/12/96
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118
The following items are not included in the cost estimates:
New 180 meter high stack for the boilers
Cost of Turbine No. 12 because it is already bought
Ash Sluicing and Storage System for the entire plant
Fish Protection System
ID fans, FD fans and various pumps for all boilers and turbines except for Boiler No. 16 and
Turbine No. 12
Boilers and Turbines refurbishment for the rest of the units at the plant
Station piping of main steam and feedwater system except for Turbine No. 12
I&C for balance of plant except for Line No. 7 (Boiler No. 16 and Turbine No. 12)
The project cost estimate is conceptual in nature, and was based on information obtained during
Burns and Roe's site visit in March 1995.
Direct Cost
Pricing for major equipment and materials were developed from Burns and Roe historical data
and vendor estimates for similar sized projects escalated to December 1995. The pricing is based
on major equipment and material being supplied by Western manufacturers and transported to the
project site.
Bulk materials (concrete, piping, valves, etc.) were assumed to be available locally in the
quantities and sizes necessary to support the project requirements.
Construction Labor
Labor costs were generated by using U.S. Gulf Coast manhour estimates for the work to be
performed and applying a productivity factor. The productivity factor was developed based on
Burns and Roe's observations at the site and previous studies performed in NIS countries. Based
on our site visit, we expect the skilled labor required to complete the project will be available
locally to the project and within Kazakstan.
Indirect Costs
Ocean freight costs and insurance costs have been assumed at 7% of material costs.
Contingency has been added to the estimate to provide for risks and uncertainties associated with
the scope of work at the conceptual stage of design. Contingency was applied to the direct labor
and material costs.
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119
Other Costs
Additional costs such as Engineering, Construction Management, Start-up Costs, Construction
Equipment, Interest During Construction, and Escalation have not been included in the base cost
but are presented for information purposes. These costs are listed on sheet 3 of the cost estimate.
These costs are applicable to similar electric power plant rehabilitation projects in the United
States. However, they may have to be modified for reconstruction projects in Kazakstan based on
local construction practices and traditions.
5909-98C/UST.DOC/2/12/96
57
120
PRELIMINARY COST ESTIMATE
INSTALLATION OF NEW BOILER No. 16 and TURBINE No. 12
UST-KAMENOGORSK COMBINED HEAT & POWER PLANT KAZAKSTAN
ITEM
LABOR
MAT'L
LOCAL
TOTAL
COST $
$
MAT'L COSTS
COST
NEW BOILER No. 16
Supply & Install New BZK-420 Natural Circulation Boiler
680,000
18,400,000
368,000
19,448,000
Supply & Install New Low NOx Burners & OFA System
100,800
1,200,000
24,000
1,324,800
Supply & Install New Ball Mills & Classifiers
135,200
1,380,000
27,600
1,542,800
Supply & Install New PA/PC Ductwork & Fans
112,000
1,654,000
33,080
1,799,080
Supply & Install New Bottom Ash Removal System
59,200
385,000
7,700
451,900
Supply & Install New Boiler Supports, Platforms, Handrail & Stairs
54,400
250,000
5,000
309,400
Supply & Install New Tubular Air Heater
92,000
965,000
19,300
1,076,300
Supply & Install New Boiler Refractory, Insulation & Casing
75,200
375,000
7,500
457,700
Supply & Install New Induced Draft Fans
36,000
680,000
13,600
729,600
Supply & Install New Flue Gas Ductwork w/ Insulation & Lagging
149,600
1,020,000
20,400
1,190,000
TOTAL BOILER WORK
1,494,400
26,309,000
626,180
28,329,580
REHABILITATION OF TURBINE GENERATOR
Install New 80 MW Turbine
496,000
0
19,840
515,840
Supply & Install New Generator
188,000
4,985,000
7,520
5,180,520
Supply NDE Testing Equipment
0
35,000
0
35,000
TOTAL TURBINE WORK
684,000
5,020,000
27,360
5,731,360
AUXILLIARY PLANT SYSTEMS
Complete Installation of Existing Condenser
49,600
0
7,440
57,040
Supply & Install New Circulating Water Pumps & Piping
312,000
585,000
11,700
908,700
Supply & Install New Coal Handling System incl Railcar Dump
288,000
3,445,000
68,900
3,801,900
Supply & Install New Demineralizer & Wastewater System
329,600
3,570,000
71,400
3,971,000
Supply & Install New HP Feedwater Heaters
187,200
340,000
6,800
534,000
Supply & Install New LP Feedwater Heaters
168,000
225,000
4,500
397,500
Supply & Install New Feedwater Pumps
48,000
600,000
12,000
660,000
Supply & Install New Main Steam Piping
96,000
934,000
18,680
1,048,680
Supply & Install New Extraction and Drain Piping & Valves
16,000
135,000
2,700
153,700
Supply & Install New Condensate Pumps
28,000
210,000
4,200
242,200
Supply & Install Miscellaneous Auxilliary Equipment
92,800
822,000
16,440
931,240
Supply & Install New Cooling Tower
209,600
2,615,000
52,300
2,876,900
TOTAL AUXILLIARY SYSTEMS
1,824,800
13,481,000
277,060
15,582,860
58
02/09/96
SHEET 1 OF 3
PRELIMINARY COST ESTIMATE
INSTALLATION OF NEW BOILER No. 16 and TURBINE No. 12
UST-KAMENOGORSK COMBINED HEAT & POWER PLANT KAZAKSTAN
ITEM
LABOR
MAT'L
LOCAL
TOTAL
COST $
$
MAT'L COSTS
COST
INSTRUMENTATION & CONTROLS
Supply & Install Emissions Monitoring Equipment
41,600
480,000
9,600
531,200
Supply & Install Boller Monitoring Equipment
28,000
275,000
5,500
308,500
Supply & Install New Turbine Governing System
36,800
110,000
2,200
149,000
Supply & Install Miscellaneous Instrumentation & Controls
102,400
644,000
12,880
759,280
TOTAL INSTRUMENTS & CONTROLS
208,800
1,509,000
30,180
1,747,980
ELECTRICAL SYSTEM
Supply & Install New 110kv Substation
158,400
844,000
16,880
1,019,280
Supply & Install New Cable, Conduit & Cable Tray
418,000
1,432,000
28,640
1,878,640
Supply & Install New Instruments & Controls
172,000
622,000
12,440
806,440
TOTAL ELECTRICAL WORK
748,400
2,898,000
57,960
3,704,360
ENVIRONMENTAL SYSTEM
Supply & Install (4) New Venturi Scrubbers for Boiler No. 16
316,000
1,630,000
32,600
1,978,600
TOTAL ENVIRONMENTAL WORK
316,000
1,630,000
32,600
1,978,600
DISTRICT HEATING SYSTEM
Install District Heating Heat Exchangers, Piping & Valves
284,000
1,777,000
35,540
2,096,540
Install New Make-up Water System for District Heating
325,000
2,120,000
42,400
2,487,400
Install District Heating Water Circulating Water Pumps
116,000
545,000
10,900
671,900
Install District Heating Heat Exchanger Drain Pumps
37,600
69,000
1,380
107,980
Install District Heating Pump Variable Speed Drives
62,400
800,000
16,000
878,400
Supply & Install District Heating Instruments & Controls incl SCADA
52,000
1,038,000
20,760
1,110,760
Repair/Replace District Heating Piping
896,000
15,100,000
302,000
16,298,000
Repair/Replace District Heating Valves
9,000
97,000
1,940
107,940
Replacement of Industry Steam Distribution Piping
45,000
735,000
14,700
794,700
TOTAL DISTRICT HEATING WORK
1,827,000
22,281,000
445,620
24,553,620
SUBTOTAL
7,103,400
73,128,000
1,396,960
81,628,360
Freight
5,713,985
Contingency (10%)
8,162,836
TOTAL COST OF REHABILITATION
95,505,181
NOTES:
(1) ALL COSTS ARE SHOWN IN JANUARY 1996 DOLLARS
(2) PRICING DOES NOT INCLUDE A NEW STACK
(3) PRICING DOES NOT INCLUDE ASH STORAGE POND SYSTEM & FISH PROTECTION SYSTEM
(4) PRICING DOES NOT INCLUDE A NEW TURBINE. THE TURBINE IS ALREADY DELIVERED
AND IN STORAGE AT THE PLANT SITE
02/09/96
SHEET 2 OF 3
59
IF THIS PROJECT WERE TO BE CONSTRUCTED IN THE USA
THE FOLLOWING ADDITIONAL COSTS WOULD APPLY:
DIRECT COSTS FROM PREVIOUS PAGE
95,505,181
Engineering Costs
4,897,702
Construction Management Costs
2,448,851
Start-Up Costs
1,632,567
Construction Equipment Costs
1,750,000
Interest During Construction
7,640,414
Escalation
9,109,977
TOTAL COST INCLUDING THE ITEMS ABOVE
122,984,693
1. Freight Costs are assumed to be 7% of the Material Costs
2. Construction Equipment Costs assumes Equipment to be available locally to the project
3. Engineering Costs are assumed to be 6% of the Material Costs
4. Construction Management Costs are assumed to be 3% of the Material Costs
5. Start-up Costs are assumed to be 2% of the Material Costs
6. Interest during construction is calculated at 8% per year for 2 years for 1/2 the direct cost
7. Escalation is assumed to be 4% per year for 2 years
60
02/09/96
SHEET 3 OF 3
Ell
6.0
CONSTRUCTION SCHEDULE
The construction schedule for the rehabilitation recommendations described in Section 4.0 is
shown on the following two pages. The overall duration of the reconstruction (rehabilitation)
project is estimated at 24 months based on Burns and Roe past experience with similar
rehabilitation projects. Time period of 24 months only includes the actual reconstruction of the
power plant components and their startup and checkout activities. It does not include the
engineering and design time required for rehabilitation of plant components such as boilers,
turbines, auxiliary plant system components, and instrumentation and controls, nor does it include
time required for procurement of the new equipment such as new instruments and controls, or the
time required for the NDE of boiler pressure parts.
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124
CONSTRUCTION SCHEDULE FOR
.É UST KAMENOGORSK LINE NO. 7
Tasks
Month 1
Month 2
Month 3
Month 4
Month 5
Month 6
Month 7
Month 8
BOILER WORK (BOILER NO. 16)
Install New Boiler and Associated Equipment
Install New Mills and Associated Equipment
TURBINE GENERATOR (TURBINE NO. 12)
Install New Turbine/Generator and Auxiliaries
AUXILIARY PLANT SYSTEM
Install New Associated Feedwater Heater System
Install New DH Interconnection Piping, Valves, and Components
Install New Associated Condensate Piping and Valves
ENVIRONMENTAL
Install New Scrubber System (Boiler No. 16)
INSTRUMENTATION
Install Emissions and Air Flow Monitoring Equipment
Install Boiler and Turbine Monitoring Equipment
DISTRICT HEATING SYSTEM
Repair and/or Replace Deteriorated Piping Sections
Install New District Heating Pumps
Install New Instruments and Control System (SCADA)
STARTUP AND CHECKOUT
Page 1
CONSTRUCTION SCHEDULE FOR THE UST KAMENOGORSK LINE NO. 7
Month 9
Month 10
Month 11
Month 12
Month 13
onth 1
Month 15
Month 16
Month 17
Month 18
Month 19
Month 20
Month 21
Month 22
Month 23
Month 24
Page 2