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PN. ACB-860
96293
Burns and Roe Enterprises, Inc.
Technical Report
KAZAKSTAN EXPANDED ENERGY PROGRAM
HEAT AND POWER SYSTEM EFFICIENCY
IMPROVEMENTS
ERMAKOVSKAYA & EKIBASTUZ PLANTS
FINAL REPORTS
December 1995
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) 986-4459 Telex 215058 Cable BURNS ROE ORA
January 19, 1996
Mr. Iqbal Chaudhry
Energy Officer
U.S. Agency for International Development
AID/EEUD/E&I/EI
Room 440 - NS, Department of State
320 21st Street NW
Washington, D.C. 20523
Subject:
Kazakstan - Final Report
Expanded Energy Program
Heat and Power System Efficiency Improvements
Ermakovskaya and Ekibastuz 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 Ermakovskaya and Ekibastuz plants. Karaganda and
Ust-Kamenogorsk final reports will be issued on January 26, 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 in engineering and construction since 1932
Mr. Iqbal Chaudhry
January 19, 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. Popovic
Project Director
cc:
All w/att
G. Weynand, USAID
B. Primm, USAID, Almaty
S. Gerges, Burns and Roe
TABLE OF CONTENTS
KAZAKSTAN EXPANDED ENERGY PROGRAM
TASK 2
HEAT AND POWER SYSTEM EFFICIENCY IMPROVEMENT
ERMAKOVSKAYA POWER PLANT
1.0
Introduction and Objective
2.0
Kazakstan Energy Sector Strategy
3.0
Block No. 3 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
4.0
Block No. 3 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
Rehabilitation Benefits
5.0
Capital Cost Estimates
6.0
Construction Schedule
7.0
Evaluation of Ermakovskaya Block 2 Rehabilitation
5909-98A/TOC/12/29/95
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 NOₓ burner
VM
Volatile matter
FC
Fixed carbon
HGI
Hardgrove Grindability Index, HGI = (Kₚ₀ -0.32)/0.0149
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
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/TOC/12/29/95
ii
ERMAKOVSKAYA PLANT
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 Erkamovskaya Electric Generation (Power) Plant, Block No. 3 is one of the
selected plants for energy efficiency improvements study.
5909-98A/No-3.DOC/1/17/96
1
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
selected units. The effect of improving the quality of the coal on plant performance was also
determined and is included in Appendix I. 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 recommend state-of-the-art technology
for increasing the availability and performance of the selected units. These
analyses also include 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. The effect of coal quality
improvement on increased plant performance is also included.
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/No-3.DOC/1/17/96
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
5909-98A/No-3.DOC/I/17/96
3
environment, the power sector must upgrade its environmental control equipment at heat and
power generating stations. Installation of NO, 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.
5909-98A/No-3.DOC/1/17/96
4
3.0
BLOCK NO. 3 EQUIPMENT DESCRIPTIONS AND EVALUATIONS
3.1
STEAM BOILERS DESCRIPTION AND EVALUATION
Block No. 3 consists of a supercritical steam pressure 300 MW. turbine generator with double
block boilers. The boilers are the once through type (OT), with the designation PP-950-255-2K
(P-39-2) of the "T" type configuration and manufactured by the Podolsk Machine Building Co.
The total main steam flow from the block is 950 te/h and the total reheat steam flow is 760 te/h.
The corresponding temperatures for main and reheat steam are 545°C, with a main steam pressure
of 255 at abs. The economizer receives feed water at a temperature of 265°C. The boilers have
opposed wall horizontal swirl type burners and a balanced draft, dry bottom furnace.
The table below shows the design and current operating parameters of the boilers:
Parameter
Units
Design
Current
For Both
Boiler
Boiler
Boilers
3A
3B
Main steam flowrate, total
te/h
950
432
411
Main steam pressure
at.abs.
255
238
238
Main steam temperature
°C
545
542
542
Reheat steam flow, total
te/h
760
Reheat steam pressure
at.abs
40
Reheat steam temperature
°C
545
Feedwater temp. to economizer
°C
265
214
214
Comb. air temp. to main airheater
°C
30
31
31
Comb. air temp. lvg. main airheater
°C
331
295
295
Fluegas temp. lvg. main airheater
°C
130
150
150
Boiler efficiency, LHV basis
%
91.8
88.65
80.95
The Block 3 boilers have over 150,000 operating hours. They are experiencing a higher than
normal frequency of tube ruptures and other problems.
The boilers and their auxiliaries present serious problems. Because of the deteriorated condition
of the boilers, an insufficient quantity of steam is generated. Therefore, the units are operated
5909-98A/No-3.DOC/1/17/96
5
with the top heaters out of service so that the steam which should be extracted for the heaters
may be retained in the turbines to provide additional generation. This mode of operation results in
lower turbine cycle efficiencies.
Steaming Rate
Perhaps the most important issue regarding the boilers is steam generation rates. Currently, the
two Block 3 boilers are unable to produce their Maximum Continuous Rating (MCR) capacity.
There are several problems which are working together to cause this situation. These are
discussed below:
a)
Coal Quality
The quality of the coal being provided by the mines at Ekibastuz is now typically poorer
than originally anticipated by the design. Coal mineral matter percentages are higher;
therefore, percentages of fixed carbon, volatile matter and coal heating values are lower.
This means more coal must be pulverized to meet the energy needs of the boilers, and
more combustion air is needed to assure complete combustion. Unfortunately, more
pulverized coal is needed than the hammer mills can provide, and more air is needed than
the fans can handle, limiting boiler output. Increased convective pass fluegas velocities,
and increased fluegas flyash content result in increased tubing erosion metal loss.
b)
Unburned Fuel in Ash
Obviously, the amount of unburned coal in the ash from a coal-fired boiler should be
minimal. Coal in the ash is coal which costs the utility money but produces nothing of
value. Based on discussions with the plant engineers at Ermakovskaya, the ash there
typically contains about 4 or 5% unburned carbon. This translates directly into a heat loss
impact on boiler efficiency. With the coal mills failing to meet the needs of the boiler, this
unburned coal also leads to a reduction in MW output.
c)
Air Infiltration
The unmeasured air which leaks in through worn seals on the fans and air heaters, and
through corrosion/erosion induced holes in the boiler setting has a profound effect on the
thermal performance of the boiler. The air which leaks in does not contribute to the
combustion process because it does not pass through the burners. This infiltration air
contributes very little to the processes taking place in the boiler, but absorbs considerable
heat as it is heated from near ambient to a much higher fluegas temperature. The
infiltration air also adversely affects I.D. fan performance. The fans have a fixed amount
of drive motor power available to deliver flue gas up the stack. Power expended moving
infiltration air is not available to move flue gas.
5909-98A/No-3.DOC/1/17/96
6
d)
Boiler Pressure
Boiler main steam pressure is deficient. This adversely affects steam turbine output and
heat rate.
e)
Boiler Slagging
Uncontrollable furnace tubewall slagging deposits due to lack of or inadequate number of
furnace wall blowers, increased coal mineral matter content, too high furnace burner zone
heat release rates, unequal fuel and air distribution between burners.
All of the above-described problems work together to reduce the overall boiler efficiency and to
reduce the boiler steam output to the steam turbine. Although this situation can be partially
corrected by repairing the air-infiltration leaks, the other problems must also be addressed. More
mill capacity can improve pulverized coal fineness (reducing unburned fuel in the ash) and also
assure that adequate fuel quantities are prepared to meet the boilers' needs. Replacing the existing
bare tubing with extended surface primary superheater and economizer tube banks (kept clean
with adequate sootblowers) will improve heat transfer performance of these heating surfaces.
Hopefully, all these measures can work together to provide an adequate steaming rate.
Availability
Ermakovskaya, Block 3 has been in operation for well over 150,000 hours, and is beginning to
show signs of age-induced deterioration (in the form of outages due to failure of boiler pressure
parts). Those areas where operating experience suggests possible degradation due to low cycle
fatigue, creep etc., should be subjected to NDE to identify specific areas needing further attention.
Repairs should be accomplished, where necessary, or replacements, if required.
5909-98A/No-3.DOC/1/17/96
7
Coal Pulverizers
The coal for the plant is mined at Ekibastuz and shipped to the Ermakovskaya plant at Pavlodar
via trains. Even when Ermakovskaya was first put in operation, the coal from the Ekibastuz
region was not of a very high quality. Over the years of operation, the coal provided to the
Ermakovskaya plant from Ekibastuz has diminished in quality. Ash content has increased and
heating values have fallen. At the same time, air infiltration into the boiler setting has reduced the
boiler efficiency. The leakage is through cracks in the boiler casing caused by expansion and
contraction, openings in the casing caused by sulfuric acid corrosion and abrasive coal ash
erosion, leaks in the casing penetrations, leakage in the airheater seals, etc. All of these factors
make it necessary to burn more coal to achieve the same steaming rate. Unfortunately as the
delivery of more coal to the boiler is limited by the capacity of the currently installed pulverizers,
replacement of these pulverizers is required. The existing four high speed horizontal shaft
hammer mills per boiler should be replaced with four new larger medium speed vertical shaft
roller mill pulverizers with integral dynamic (rotating) classifiers for improved pulverized coal
fineness. This will make it necessary to remove the existing hammer mills and associated
equipment.
This modified arrangement would be sized to provide one spare pulverizer to permit on-line
maintenance, and would increase coal flow with 3-mill operation to achieve full load steaming
capacity, even with the low quality coal now delivered from the mine.
Forced Draft (FD) and Induced Draft (ID) Fans (one each per boiler)
There is insufficient FD and ID fan capacity due to serious leakage in the air and fluegas
equipment and ductwork. Even with the leakage controlled to reasonable levels, the poor quality
of the coal requires more combustion air to be sent to the burners (Leakage air does not pass
through the burners). Finally, the pollution control equipment which must be used to control the
emissions of atmospheric pollutants will affect the draft loss through the ductwork and equipment,
which must be overcome by the ID fans. This pollution control equipment will be selected later,
so the ID fan requirements have not yet been established. To be safe, all fans should be
performance tested and the results compared to the performance needed when the pollution
control equipment is installed. Then the decision can be made to either refurbish or replace the
fans. In the interim, the cost of refurbishment, foundation skids, etc. will be recommended for
addition to the budget for the FD fans. The cost of replacement will be added for the ID fans
when the fan requirement is established.
Heating Surfaces/Wall Blowers and Sootblowers
Since it is currently not possible to achieve Maximum Continuous Rating (MCR) due to the
various problems, attention should be directed toward increasing heat transfer to achieve
design-rated steaming rates and higher, design-rated superheat and reheat temperatures. To
achieve this, extended surface primary superheater and economizer tube banks should be
5909-98A/No-3.DOC/1/17/96
8
retrofitted with in-line centers, replacing the existing bare tube banks on staggered centers. The
extended surface tubing will maintain the effective surface and heat transfer, but may also increase
the possibility of fouling.
The Ekibastuz coal has a relatively abrasive ash. Because of this, the existing boilers may be
operated without sootblowers in the convection passes. One boiler has sootblowers. The 3b
boiler also has wall blowers for removing slag in the furnaces. With the retrofit of extended
surfaces in the convection passes, it will be necessary to add sootblowers to the convection passes
of both boilers to avoid fouling of the extended surfaces. This is particularly important with the
high ash of the Ekibastuz coals. A full complement of wall and sootblowers will need to be
installed on boiler 3a.
Furnace Ash Hopper Tubing
The horizontal tubing in the Block 3 boiler furnaces hopper walls should be replaced with vertical
tubing to improve ash and slag evacuation, and to improve resistance to slag falls.
It is understood that the Plant is replacing the horizontal circuits of the Block 2 furnace
tubehopper walls with vertical circuits.
Low NO3 Burners and Overfire Air
Although the environmental assessment will be done later, it is almost certain that low NO,
burners with or without overfire air ports will be a part of the planned boiler emission control
program. The spacing of the retrofit burners may have to be increased so as to reduce the burner
zone heat release rate and consequently the furnace slagging deposits.
Tube Penetration Seals
The current condition of the tube penetration seals is unsatisfactory. Tube penetration seals of
furnace and backpass roof tubes, and in backpass tube banks for superheaters, reheaters, and
economizers are leaking and permitting air infiltration.
Air Heaters
Refurbish and repair rotary, regenerative, bi-sector vertical shaft air heaters two per boiler,
including radial and circumferential seals, cold end sectors of rotors, sootblowers, etc. as required.
Condition Assessment of Pressure Parts
A boiler condition assessment should be done on furnace, SH, RH tubing and water/steam-cooled
thick-walled pressure parts; i.e., headers, desuperheater piping, integral piping etc.
5909-98A/No-3.DOC/1/17/96
9
One of the sources of boiler unavailability is frequent furnace tube ruptures (156 in 1993, 177 in
1994 for the total of 16 boilers). Also the two boilers of unit 3 have average operating periods in
excess of 150,000 hours, each. Thus a non-destructive (ND) examination of the pressure parts of
one of the two boilers of Block 3 appears warranted. Following a review of the findings, remedial
action should be undertaken.
Furnace and Boiler Setting
Setting leaks are a major problem. Air infiltration is impacting on fan capability, boiler efficiency,
and unit peak capacity. Consequently, setting refurbishment is a priority item. This would
include the refurbishment of the following on each boiler:
Boiler refractory, insulation, casing (BRIC) refurbishing as needed, of furnace vertical
walls, tube hopper slopes, furnace and backpass roof, two symmetrical backpasses walls,
boiler outlet fluegas ducts and flyash hoppers.
Certain routine maintenance activities, including routine repairs and replacements, replenishment
of lubricants,etc., are stipulated. These items should be accomplished in good order, and on
schedule or as soon after as is possible.
Unequal fuel and combustion air distribution between burners
Both the primary air/pulverized coal (PA/PC) as well as the secondary air maldistribution between
individual burners will have to be improved to (a) eliminate local reducing atmosphere furnace
conditions and resulting slag type deposits and (b) to reduce unburnts in ash and increased carbon
monoxide production. These requirements take on added importance with the retrofit of LNBs.
3.2
STEAM TURBINE GENERATORS
General
Many problems with the turbines and auxiliaries have been identified from discussions with plant
personnel, and from review of documentation received. These problems have resulted in an
increase in Block heat rate, higher operating costs, increased unscheduled outages and lost
generation due to equipment failure. Some of the problems will require increased future
inspections and deficiency corrections of internal and external components of the turbine, which
will result in Block outage time and increased maintenance expenses.
The eight steam turbines at the Ermakovskaya power plant have a combined design capacity of
2400 MW. However, the total working output for the plant at the time of the Burns and Roe
team visit was only 1550 MW. This was mainly due to the problems with the quality of coal
burned and the air inleakages described under paragraph 3.1. However it was noted that with
relatively "good coal", the mineral matter content of which does not exceed 40%, a total gross
5909-98A/No-3.DOC/I/17/96
10
generating output of 2160 MW can be achieved. The maximum steam generating capability of the
steam boilers with such a coal and the corresponding maximum power output of the eight turbines
are shown in Table 3-1.
TABLE 3-1
MAXIMUM CURRENT GENERATING CAPABILITY OF
THE ERMAKOVSKAYA UNITS
Block No.
1
2
3
4
5
6
1
8
Steam Flow
700
800
970
960
1000
1000
980
980
(t/h)
Turbine
210
240
280
260
300
300
280
290
Output (MW)
No. of Oper.
175,075
170,326
169,462
165,954
150,522
151,869
149,094
145,310
Hrs. to 1/1/95
The operating data for the plant collected for the year 1994 indicates that the plant output is at its
maximum during the winter months. The total electrical generation, the peak loads, and the
monthly average loads supported by the plant during 1994 are shown in Table 3-2.
TABLE 3-2
SEASONAL GENERATION AND LOADS FOR ERMAKOVSKAYA
(1994)
MONTH
AVERAGE LOAD
PEAK LOAD
GENERATION
(MW)
(MW)
(10³ kWh)
January
1844
2080
1281564
February
1969
2070
1182982
March
1708
1965
1133058
April
1456
1770
960321
May
1485
1770
998237
June
1275
1535
830887
July
1230
1430
800434
August
1507
1780
984591
September
1151
1550
774441
5909-98A/No-3.DOC/1/17/96
11
October
1493
1505
785665
November
1752
1875
907926
December
1604
1880
1125899
From the above table, it can be seen that the average 1994 load on the plant was 1539.5 MW.
Plant personnel indicated that the expected average output from the plant through the year 2005
is estimated at 1900 MW due to the reconstruction of the various power blocks.
The reconstruction plan includes rehabilitating the units in the following order: Blocks 2, 3, 4, 1,
5, 6, 7, 8. Reconstruction of all units is expected to be completed by the year 2016.
Because of block 2 and block 3 were the first units to be rehabilitated it was decided to examine
these units in detail. Since the reconstruction plan has already been developed for block 2 Burns
and Roe has reviewed it as to its appropriateness but more significant effort was made to evaluate
block 3 and to develop recommendations for its reconstruction.
Description of Turbines
The Ermakovskaya block 2 and 3 turbines are nominal 300 MW, 3000 rpm, single reheat, tandem
compound condensing machines, designed to receive 977 te/h of supercritical throttle steam at a
pressure of 232 at abs. and temperature of 540°C at normal full load operation. There are three
separate turbine elements on a single shaft; one single flow high pressure (HP) section, one single
flow intermediate pressure/low pressure (IP/LP) section, and one double flow low pressure (LP)
section. A cross sectional drawing for the turbine is shown in Figure 3-1.
The number of stages in the turbine are 11 in the HP section, 12 in the IP/LP section and 5 in each
half of the double flow LP section. Interstage steam sealing strips are provided to minimize
bypass of steam around rotor blades and diaphragm nozzles.
Exhaust steam from the HP turbine is passed through the reheater in the boiler, and returned to
the IP/LP section of the turbine. After passing through the IP section stages, some of the steam
continues through the LP stages of the IP/LP section of the turbine. The remaining steam is
distributed to the double flow LP section of the turbine via cross-over pipes.
Steam is extracted from nine stages of the turbine, and directed to six stages of low pressure
feedwater heating, three stages of high pressure feedwater heating, a feedwater pump turbine, and
deaerator. The thermal cycle diagram for the existing steam turbine is shown in Figure 3-2.
Exhaust steam from the LP sections of the turbine is condensed at approximately 0.0374 at abs. in
a two pass shell-and-tube surface condenser, located under the LP turbine.
5909-98A/No-3.DOC/1/17/96
12
Condensate from the condenser is heated through nine stages of feedwater heating and is
delivered to the boiler at the rate of 977 te/h and a temperature of 276°C.
5909-98A/No-3.DOC/1/17/96
13
Figure 3-1 Cross Section of Turbine
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Figure 3-2 Thermal Cycle Diagram
5909-98A/No. 3/12/8/95
15
Design/Current Performance of Block 3
The K-300-240 steam turbines used at the Ermakovskaya power plant were originally designed
for the conditions shown in the first column of Table 3-3. This column indicates that the original
main steam and hot reheat steam temperatures were 560 and 565°C, respectively. Because of the
various problems from the effect of using these high temperatures in critical thick walled pressure
components (steam generator headers, HP/IP turbine shells, etc.) the then Soviet regulatory
agency officially lowered the main steam and hot reheat steam temperatures to 540/540°C. This
change is reflected in the second column of Table 3-3.
TABLE 3-3
TECHNICAL CHARACTERISTICS OF THE STEAM TURBINE
Original Design
Modified Conditions
Type
K-300-240
K-300-240
Nominal Output, MW
300
300
Main Steam Pressure, kg/cm²(a)
240
240
Main Steam Temperature, °C
560
540
Hot Reheat Temperature, °C
565
540
Maximum Output, MW
320
300
Main Steam Flow at above Output, t/h
950
940
Number of Extractions
9
9
Extraction Configuration
3HPH+D+6LPH
3HPH+D+6LPH
Condenser Pressure, kg/cm²(a)
0.035
0.035
Specific Heat Consumption kcal/kWh
1830
1955
Turbine Manufacturer
Kharkov
Kharkov
Overall Length of T-G, m
35.8
35.8
Number of Turbine Bearings
5
5
Generator Model
TVG-300
TVG-300
Generator Cooling Medium
H₂
H₂
5909-98A/No-3.DOC/1/17/96
16
Even though the unit has operated during the last 24 years with these lower steam conditions the
specific heat consumption (heat rate) of the turbine has degraded significantly due to various
reasons. Operating data for the year 1994 obtained from the plant for all blocks indicates that the
Block 3 steam turbine was running for a period of 5317 hours, with average monthly load varying
between 172 MW and 231 MW. During the months of August and September Block 3 was not
utilized. In addition the actual operating data indicated that the average heat rate of the unit
varied between 1943 and 2604 kcal/kWh. Block 3 heat rate at the time of our visit was about
2240 kcal/kWh.
In order to establish the actual current degradation of the turbine heat rate and to see how close
the above stated heat rate can be substantiated, Burns and Roe has performed calculations based
on the available efficiency data and operating mode for Block 3. Although official performance
test data was not available for Turbine No. 3, such a test was recently conducted on Block No. 4.
Since these units are similar to one another, and have been subject to the same operating and
maintenance conditions, their condition should be similar, with the following exceptions:
Block No. 3 Turbine has the lowest HP and IP efficiency of all turbines and has been
running with the second stage blades removed in the LP section.
Block No. 3 has been running with one string of high pressure feedwater heaters out of
service.
The actual HP and IP turbine efficiency figures determined by the plant personnel as of January 1,
1995 for the various steam turbine units are shown in Table 3-4.
Utilizing the differences between the design and actual internal efficiencies and assuming an
average efficiency degradation for the LP section to be between those of the HP and IP section,
the degradation of heat rate within each of the three turbine sections was calculated. This
required first the calculation of the portion of the electric output generated in the individual
turbine sections. The percent efficiency degradation multiplied by the work done in the
corresponding turbine section were added up and applied to the modified heat rate of 1955
kcal/kWh. This methodology of calculating the actual heat rate was also used to the results and
data of the Block 4 performance testing to serve as a check of the appropriateness of the
calculation, and a good correlation was found.
5909-98A/No-3.DOC/1/17/96
17
TABLE 3-4
TURBINE STEAM FLOW PATH EFFICIENCIES
(As of January 1, 1995)
Turbine Block
HP Efficiency
IP Efficiency
Actual
Normative
Actual
Normative
#1
72.7
75.0
83.8
90.0
#2
70.6
75.6
75.7
89.0
#3
69.9
73.0
74.7
89.6
#4
72.0
80.0
82.9
89.0
#5
75.8
79.2
86.3
89.0
#6
N/A
N/A
N/A
N/A
#7
74.0
79.0
85.9
89.5
#8
72.8
80.0
85.4
89.5
Finally, the effect of operating the block 3 turbine with a closed-out string of high pressure
feedwater heaters was factored in resulting in a further degradation of heat rate. Combination of
all the above conditions resulted in a degraded current heat rate of 2222 kcal/kWh.
Based on the obtained figure the heat rate was found to be degraded by
2222 - 1955 X 100 = 13.6%
1955
if the modified heat rate of 1955 kcal/kWh (shown in Table 3-3 is used as a base. However,
based on the original design heat rate of 1830 kcal/kWh the current heat rate degradation of the
block 3 turbine is 392 kcal/kWh or
2222 - 1830 X 100 = 21.4%
1830
As far as the turbine output is concerned it was reported that the maximum output that can be
obtained from the block 3 steam turbine is 280 MW. The closing out of one high pressure
feedwater heater results in a power increase of about 20 MW. The 280 MW output is only
possible when the main steam flow to the turbine is about 976 t/h.
5909-98A/No-3.DOC/1/17/96
18
Condition Assessment
a)
Block 3 Problems
Many problems with turbines and auxiliaries have been identified from discussion with plant
personnel, and from review of documentation received. Some of these problems have resulted in
an increase in block heat rate, which in turn results in higher operating costs. Other problems
increase the probability of unscheduled outages resulting in lost generation due to equipment
failure. Some of the problems will require increased future inspections and deficiency corrections
of internal and external components of the turbine, which will require unit outage time and result
in increased maintenance expenses. Significant problems, which have been identified relative to
Number 3 turbine and auxiliaries, are outlined below:
Turbine Steam Path/Blading
As it can be seen from the efficiencies shown in Table 3-4, the components of the steam path in
block 3 have significantly deteriorated. The causes of the deterioration are simply wear due to
age, but also the result of moisture erosion of the last stage blades, solid particle erosion of the
first stage blades, as well as some problems due to water induction. The following significant
failures of turbine blades were reported on block 3:
-
Failure of the 3rd stage blades in October, 1986. These blades were replaced.
-
Failure of 2nd stage blade in the low pressure section in November, 1992. The
turbine has been operated without 2nd stage blades for two years.
-
Failure of two blades in the 4th stage in January, 1994.
-
Solid particle erosion on first stage blades.
-
Considerable erosion problem on last stage blades, requiring repair approximately
every 6 to 8 years.
A 5 mm buildup of solid particles in the first stage of was reported. Attempts were made to
remove the deposits by reducing the load to 60 MW and running the turbine at reduced steam
conditions of 60 kg/cm² and 300-310°C for about 6-8 hours. In the past (before 1986), this
operation had to be performed once or twice a year. In 1986 the plant changed to oxygenated
water chemistry which improved this situation. Now similar operation is still performed but less
frequently, only about once or twice in four years. The first stage blades had to be changed once
(this is also true for block 2, 5 and 7).
The last stage blades (1050 mm long) repeatedly erode requiring replacement every 6-8 years.
The last stage blade shroud is also frequently breaking causing additional shaft vibration, and
5909-98A/No-3.DOC/1/17/96
19
damage to condenser tubes. In addition to the above, a decrease in efficiency originates from the
increased interstage leakages within the turbine due to wear. Furthermore the gland steam
leakage from the labyrinth seals was reported to be twice than that of the original design values.
Water Induction
It was reported that Block 3 had water induction incidents originating from LP Heater No. 2 at
the 8th extraction point. After the incident a valve was installed in the extraction line. This water
induction incident caused failure of the blades in the 3rd stage of the Low Pressure Turbine.
Presently, Extraction No. 9 appears to be the only extraction to contain no automatically actuated
valves for protection against water induction into the turbine, and the serious damage which could
be inflicted on the turbine in such an event. All other extraction steam lines have non-return and
isolation valves installed.
Turbine Thrust Bearing
The thrust bearing consists of eight Babbited metal segments, and its condition is significantly
deteriorated. Part of the problem may have been caused by the high pressure differential between
stages of the turbine due to the water induction. However, the deterioration is mainly due to shell
misalignment problems which causes excessive rubbing between the contact points for the
segment supports which actually became essentially flat surfaces. This causes increases both in
temperature and turbine vibration. The thrust bearing should have been replaced but
unfortunately replacement parts are not readily available.
Turbine Support and Alignment
There are serious alignment problems associated with the No. 3 turbine. During turbine start-up,
misalignment of the turbine shells at the support between the HP and IP sections causes failure of
the labyrinth steam seals and bearing oil seals, thereby increasing leakage across the seals.
Leaking oil flows out onto the floor. Because of the close proximity of the bearing glands to the
turbine glands, condensate is easily cross-contaminated with oil. The problem soon reappears
even after a startup following a major overhaul. This problem also exists with Block 2 turbine.
Turbine Control and Monitoring Equipment
A large percentage of the 11 breakdowns of the block 3 turbine in 1994 (Block 2 had only 6
breakdowns) were due to problems at the valves in the control systems of the turbine as well as
vibration problems. The steam turbine regulating valves often had failures at the valve stems,
operators and bushings. A slow closure of a regulating valve on the Block 1 steam turbine once
caused a catastrophic accident overspeeding and throwing the turbine apart, requiring a complete
replacement of the unit. The automatic regulation system and instrumentation on Blocks 2, 3, 4,
7 and 8 have not been replaced since each of these units were put into operation.
5909-98A/No-3.DOC/1/17/96
20
The instrumentation on turbine protection and monitoring is outdated, worn, and requires
replacement. The existing vibration instrument measures in three directions (horizontal, vertical,
axial), however the vibration equipment does not provide exact vibration figures at the bearing
surface. The units RPM monitoring equipment does not provide reliable monitoring during
startup. In addition the unit has no turbine stress evaluator (TSE) equipment and no life
consumption curves exist for the unit. Turbine starts are based on manual operation and
procedures based on the following startup metal temperature classification:
Cold start < 150°C
Warm start < 350 > 150°C
Hot start > 350°C
Metal temperature increases do not exceed rates between 100-150°C/hr. Observation point for
metal temperatures are at the top and bottom of the cylinders (heavy wall thickness turbine
components) and at various points at the flange connections at the turbine horizontal joints.
b)
Metal Control
The metal control laboratory personnel has been interviewed to assess the procedures and
equipment the plant has to control metal conditions. In general the plant has quite a large array of
non-destructive examination (NDE) and destructive examination (DE) equipment for the testing
and inspection of the turbine, steam generator, and main steam piping components. These
equipment include the following:
MIR-2 X-ray impulse apparatus
UD-2-12 Ultrasonic flaw detector
UDM-1M Ultrasonic flaw detector
MD-10C Magnetic flaw detector
DMI-ChM Magnetic particle defectoscopy instrument
VDL-3M Eddy-current flaw detector
VDBK-1 Eddy-current flaw detector
VD-5M Eddy-current flaw detector
VPI Hardness tester
CLU Portable Steeloscope
TIC-3, TIC-101, UT-93P Thickness Gages
R-50 Tensile-testing machine
I05003-0.3 Pendulum hammer
TK-2 Rockwell hardness tester
TS-2M Brinell hardness tester
TKC-1M Super Rockwell hardness tester
M1M-7 Metallographic microscope
MBC-9 Biological microscope
"SPECTR" Stationary steeloscope
5909-98A/No-3.DOC/1/17/96
21
"Belarus-2" Photographical magnifying apparatus
Grinding-polishing machine
As far as the steam turbines are concerned the plant personnel indicated that visual and magnetic
particle testing are carried out on the main castings and steam pipes and valves. This usually
occurs every 4 years during the turbine overhaul periods. These tests are done on the turbine HP
and IP shells and valve bodies to detect and/or observe cracks and cavities. In addition, ultrasonic
testing of the turbine blades are carried out. The turbine nozzle boxes are examined visually.
Visual inspections of these areas may also be performed during intermediate repairs.
Periodic NDE examinations, utilizing the magnetic particle method, performed on the Block 3
turbine every four years since 1978, indicated that a very large number of cracks were found in
various components of the turbine as follows:
Examination performed in 1978: 73 cracks found, with dimensions of up to 20 mm (0.78
in) in length and 9 mm (0.35 in) in depth.
Examination performed in 1982: 93 cracks found, with dimensions of up to 150 mm (5.9
in) in length and 12 mm (0.47 in) in depth.
Examination performed in 1986: 30 cracks found, with dimensions of up to 130 mm (5.11
in) in length and 54 mm (2.12 in) in depth.
Examination performed in 1990: 122 cracks found, with dimensions of up to 150 mm (5.9
in) in length and 34 mm (1.33 in) in depth.
Examination performed in 1994: 26 cracks found, with dimensions of up to 56 mm (2.2
in) in length and 35 mm (1.37 in) in depth.
These cracks occurred in various turbine components, including the shells, and various turbine
valve bodies and connecting steam piping. The distribution of total cracks found in the Block 3
turbine between the years 1978 and 1994 are shown below:
HP section
:
108 cracks
IP section
:
62 cracks
LP section
:
4 cracks
Auxiliary Turbine Components (such as valves, piping) : 170 cracks
All of the above total of 344 cracks have been repaired, as reported by plant personnel. However,
because of the history of crack development and repair in this turbine, periodic NDE inspections
will be required in the future. The discovery of additional cracks can be expected.
5909-98A/No-3.DOC/1/17/96
22
There is currently no replication type creep testing capability at this plant. As the plant is getting
older such testing capability would be highly desirable to monitor potential creep cavitation of
critical components which operate with units approaching 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.
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 rapidly as possible.
Turbine Assessment
The Block 3 steam turbine is now the second oldest machine at Ermakovskaya (since Unit 1 had
to be replaced in 1973). It was placed into operation in 1970. At the time of the Burns and Roe
team visit this unit has accumulated a total operating time of about 170,000 hours. It is similar in
construction to blocks 2 and 4 which have a double casing HP and single casing IP section (all
other turbines at the plant have double casing HP and IP sections).
Other than some blade and valve replacements the turbine is basically operating with the same
components including the control and monitoring systems, for 25 years. The allowable park
resource (the officially extended life) for the types of units operating at the Ermakovskaya plant is
220,000 hours. The block 3 steam turbine was originally designed to operate with high
temperatures of 560/565°C (main steam and superheat steam) similar to many Russian design
units. Because operation of the units at these high temperature caused considerable cracking
problems in thick walled critical steam generator components, these parameters have been
officially lowered to 540/540°C in 1971. Operation at the initially high temperature conditions
also caused some cracking in the thick walled turbine components. The number of cracks found
in the various turbine components even after the lowering of the steam temperatures is very large.
(The 344 cracks mentioned in paragraph b) above does not include cracks discovered prior to
1978). In the 12 year period from 1978 through 1990 the total number of cracks found in
various parts of the unit amounts to 318 (somewhat lower than those found in block 2 for the
corresponding period, since block 2 has been operating for a year longer than block 3). Of course
all these cracks have been repaired by either grinding or grinding and welding. Because of the
more frequent shutdown and startup of the unit due to breakdowns and due to economic dispatch,
additional cracking and more accelerated life consumption of the turbine metal can be expected.
The plant estimated a remaining life of about 40,000 hours. This seems to be in agreement with
our assessment. However, to be able to better predict the rate of life consumption and to avoid
any catastrophic failures more frequent monitoring of the metal condition of a unit would be
required. This could be best performed with the use of replication type creep testing equipment
5909-98A/No-3.DOC/1/17/96
23
which the plant currently does not have. In addition, because of the advanced age and wearout of
various components more frequent maintenance and increased maintenance costs are expected.
Data on unscheduled shutdowns for all units indicates that the block 3 block has an increased
number of forced shutdowns in recent years. As indicated above, eleven breakdowns in 1994
were associated with turbine related problems.
It should be noted that the internal efficiencies of the HP and IP sections of block 3 are the worst
among all the turbines at the Ermakovskaya Plant (see Table 3-4 above). This is an indication
that the condition of the steam flow path has significantly degraded and it is ready for
replacement. The LP section is plagued with frequent last stage blade erosion and shroud
breakage. In fact the LP section has been running with the LP 2nd stage blading removed
contributing to the low efficiency (and high heat rate of this unit). (As of this writing it is our
understanding that the 2nd stage blading was reinstalled in the LP section of block 3 utilizing the
2nd stage blading from the LP section of the currently shutdown block 2 turbine). The interstage
and gland sealing steam leakages are double than the original design.
One of the most annoying problems which plant operators are faced with is a shell support
misalignment problem at the sliding support between the HP and IP housings. Even after capital
repairs the bearing oil and steam gland seals are quickly broken causing cross contamination of
condensate and oil, and also oil leaks to the floor. In addition the thrust bearing should have been
replaced but there are no spares readily available on the market. This contributes to excessive
vibration problems for block 3. The plant personnel and metal laboratory personnel are doing
their best to keep the unit in operation and try to follow the assigned maintenance programs
(yearly, intermediate and overhaul) as closely as possible. However, block 3, because of the
above unsatisfactory factors would not be likely to provide long time reliable and efficient service
without major repairs and replacements.
3.3 AUXILIARY PLANT SYSTEMS
a) Plant Condenser
The condenser for block 3 is a Type K-15240 single pressure surface condenser with two water
passes which is connected to the three exhaust connections of the steam turbine. The technical
characteristics of the condenser are shown in Table 3-5.
5909-98A/No-3.DOC/1/17/96
24
TABLE 3-5
TECHNICAL CHARACTERISTICS OF THE CONDENSER
Type
K-15240
Design Steam Flow, t/h
563.64
Condenser Pressure, kg/cm²(a)
0.035
Circulating Water Flow, t/h
34805
Circulating Water Design Temperature, °C
12
Specific Steam Load, kg/m²h
37
Cooling Ratio
61.75
Condenser Surface Area, m²
15240
Condenser Active Tube Length, mm
8850
Circulating Water Velocity in Tubes, m/sec
1.86
Number of Tubes
18528
Tube diameter OD/ID, mm
28/24 and 28/26
Tube Material
L-68
Hydraulic Resistance, m W.C.
4
The original tubes have been replaced in 1990 and therefore the tube condition is satisfactory.
The allowable plugging in the condenser is 10%. However, the plant reported problems with the
tube-to-tube sheet joints. Circulating water can find its way into the condenser steam space
through rolled tube joints. This will require the checking of tubes for leakage and repair plugging,
or replacement as necessary based on the results of the leak check.
It was reported by plant personnel that considerable amounts of dirt accumulates in the condenser
tubes, especially during Spring and Summer. It appears that a condenser tube cleaning system
(such as the Tapprogge type) should be installed at this unit. Currently only Block 6 has an on-
line tube cleaning system, the other units use a high pressure air/water gun for intermittent
cleaning of condenser tubes.
In addition, the condenser is experiencing excessive air in-leakages lately. This is because of the
more frequent startups and restarts of the unit. Sometimes plant personnel have no time to fix
leakages. Average air in-leakage is about 68 kg/h. At the time of our visit the actual air in-
leakage into the vacuum system was 96 kg/h on Block 3. When there is no time to fix leaks the
plant just starts up more air ejectors. There are two (2)-75 kg/h steam jet air ejectors and one (1)
65 kg/h water jet air ejector for Block 3. Air in-leakages usually occur at the low pressure glands
and at the horizontal flange of the LP turbine cylinder.
b)
Feedwater Heaters
The unit utilizes two strings of 3 high pressure heaters and one string of low pressure heaters.
The HP heaters were manufactured by the Taganrog boiler plant and contain steam cooling,
5909-98A/No-3.DOC/1/17/96
25
condensing and drain cooling zones, and spiral coils. Because they are designed for very high
pressures they have heavy wall thicknesses. The low pressure heaters are also vertical heaters but
designed with different tubing configuration. The original tubing was a copper based metal.
Some heaters were replaced with Stainless Steel tubing. There is a program at the plant for
replacing all feedwater heater tubing. Block 6 was the first unit the feedwater heaters of which
were replaced with SS tubing. Allowable tube plugging on heaters is 10%. The LP heaters on
Block 3 still have L-68 tubes. The heater TTD and DC figures are worse for the plant (5-7°C for
TTD, and 7-10°C for DCA) than for corresponding US units. The feedwater heaters have served
during their long operating lives and show signs of wear. Tube breaks in one of the LP heaters
has contributed to the water induction problem at the Block 3 steam turbine.
c)
Deaerator
There are two deaerators per power block at Ermakovskaya Plant. The deaerator storage tanks
have a 5 minute storage capacity at a feedwater flow corresponding to 300 MW output. There
have been no problems reported for the deaerators, and they appear to be in satisfactory
condition.
d)
Boiler Feed Pumps
There are many problems at the plant with the boiler feed pumps. There are two types of pumps:
turbine driven feedpumps and electrically driven pumps. In addition there are also motor driven
feedwater booster pumps.
According to discussions with plant personnel at least three feedwater pumps have problems in
the plant every month. The block 3 turbine driven feedpump is not particularly efficient (it is
running with an efficiency of about 80%). The 12.4 MW drive turbine operates satisfactorily.
However, the main pump as well as the electrically driven feedpump which is driven by an 8000
kW motor through a hydraulic coupling and a speed increasing gear at about 6000 rpm have
vibration problems. The natural wear and tear of the pump components stemming from their age
is compounded by bad maintenance. This is not because of the maintenance plan followed by the
plant but rather the inability of the maintenance people to obtain the required spare parts.
Therefore, the plant must make the spare parts themselves. However, these parts do not exactly
correspond to the design of the pumps and usually have no proper heat treatment. The
electrically driven feed pump operates with an efficiency of only 77% and has also problems with
its hydraulic coupling. Both the turbine driven and electrically driven feedpumps should be
replaced. The 3-50% capacity feedwater booster pumps operate satisfactorily.
e)
Condensate Pumps, Condensate Booster Pumps and Drain Pumps
There are three vertical 3-stage condensate pumps, model KCB-500-85, driven by 250 HP motors
at a speed of 970 rpm. The pumps' cavitation reserve is 1.6 m W.C. These pumps operate with an
5909-98A/No-3.DOC/1/17/96
26
efficiency of 75%. The condensate pumps transfer condensate to the suction of the condensate
booster pumps through the unit's condensate polisher system.
The three condensate booster pumps are similar in construction to those of the condensate pumps
except that they have a higher head and operate at a speed of 1480 rpm. They are 5-stage vertical
pumps, Type KCB 500-220, and operate with an efficiency of 75% and deliver condensate from
the condensate polishers to the deaerator. They are driven by 500 kW electric motors.
The design of the drain pumps utilized by the plant are similar to that of the condensate booster
pumps. They have the same head but smaller flow rate. They operate with pump efficiency of
only 73%, and have an auxiliary power consumption of 154 kW at their design operating
conditions.
No serious problems were reported by plant personnel for any of these pumps other than they are
old and require careful maintenance. They appear to be in satisfactory condition.
f)
Circulating Water Pumps
There are two circulating water pumps provided for each of the units at Ermakovskaya. Normal
operating speed is 485 rpm. Each of the two pumps deliver circulating water from the end of an
intake canal to each half of the condenser. Two pumps can deliver a total flow of 43200 m³/h.
The circulating water pumps are vertical, two speed, and have adjustable vanes. The maximum
operating pump head is 11 m W.C. Two main problems were reported for these pumps. One was
cavitation damage at the impeller with the original cast iron material containing high percentage of
carbon. This problem was eliminated by changing to stainless steel material. The other problem
is the wearout of the rubber bearing supporting the pump shaft. The rubber bearing was designed
to be lubricated with clean water, and it is difficult to find and procure a replacement rubber for
the bearing. However, it was noted that the lubricating water is taken from the pump discharge.
This water can be contaminated with silt and abrasive material especially during spring. Therefore
it appears that a filter should be installed in the lubricating water line upstream of the bearing.
3.4 PLANT INSTRUMENTATION AND CONTROLS SYSTEM
General
There are a number of problems with the instrumentation and controls at the Ermakovskaya Plant.
Since the startup of the plant there has been no renovation of the equipment for automatic control
and supervisory systems on Blocks 2, 3, 4, 7 and 8. At the present, the documentation on these
systems does not correspond with the equipment. This is because in the course of operating the
plant, repairs, replacements and other changes were made without updating drawings.
Work began on March of 1995 updating the controls and instruments as needed on Block 2.
Block 3 will need similar attention.
5909-98A/No-3.DOC/1/17/96
27
a)
Load Control
Block 3 turbine uses a conventional mechanical governor with a 4% droop. Main steam pressure
is adjusted by varying the feedwater pressure. The boiler fuel controllers, when in automatic, are
used to vary the fuel flow rate to the boiler for main steam temperature control. The pulverized
coal fuel 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,
but they have never had any explosions in the fuel preparation system.
Coal must be delivered in equal amounts to each burner, even under low loads. Coal flow is
controlled by volumetric feeder speed.
b)
Combustion 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 driven by the oxygen
analyzers assists the block operator in setting the correct combustion air flow rate. 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 oxygen analyzers are extractive type and consequently slow acting. The type of O₂
monitor currently in use is a paramagnetic device with about a 3 to 4 minute delay in reading. As
part of the pilot plant upgrade, the O₂ monitors will be replaced by high temperature zirconium
oxide cells which have a much faster time response.
c)
Furnace Pressure Control
There is no automatic control of furnace pressure. The position of the induced draft fan inlet
vanes is varied remotely from the control room to adjust the value of the furnace pressure.
Normal vacuum is 3 to 4 mm. Hg.
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 feedwater.
Superheater outlet temperature and a derivative of superheater inlet temperature are compared to
the setpoint to form the control deviation.
5909-98A/No-3.DOC/I1/17/96
28
There is a need for automatic control of the superheater attemperators over a wider range than is
currently used. The setpoint is currently set at the nominal superheater temperature; therefore it
does not operate automatically during startup, thus forcing the operator to manually control the
spray. If close attention is not given by the operator, overheating will occur.
e)
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 steam temperature, forced draft fan not in
service, induced draft fan not in service, no primary air fan in service, air heaters off, flame failure,
loss of feedwater flow and loss of reheat steam flow. The flame failure circuit will start mazut
flow to the burners automatically if the unit is burning coal.
f)
Burner Management System
There is no burner management system as such. However, each boiler is equipped with electronic
flame scanners, four sensors per boiler, two on the front, and two on the rear furnace wall.
g)
Stack Emissions Monitoring
There are no NO, SO₂, CO, or CO₂ measurements on these units, however the units do have
opacity monitoring. Due to the increasingly stringent requirements being promulgated by the
financing institutions a complete continuous emissions monitoring system will be required in the
future. The existing opacity monitoring system does not work well, and is not relied upon.
Currently NO, is monitored by calculation.
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.
NO, monitors will be added to the block 3 boiler flues as part of the block 3 pilot plant upgrade.
h)
Turbine Control System
The original mechanical governors are still in operation. Each turbine is equipped with 2 stop
valves and 2 interceptor valves. Contained within each stop valve are 3 governor valves and
within each interceptor valve are 2 governor valves. Control is provided by a hydraulic water
system. Speed sensors control the turbine speed by adjusting the governor valves position. The
boiler operator manually changes steam flow to adjust the load. This equipment is old and subject
to breakdown and should be refurbished.
5909-98A/No-3.DOC/1/17/96
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i)
Turbine Interlock and Protection System
The following protection interlocks are installed: excessive movement at thrust bearing
overspeed, low steam temperature, low lubricating oil pressure, high water level in HP
feedheaters, generator electrical faults, low hydrogen seal oil pressure, loss of vacuum and low
hydraulic pressure. All of the above protection and interlocks are effected via electrical relays.
Overspeed protection is provided via overspeed rings and the hydraulic fluid system.
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. Currently there is no turbine trip for high vibration, because the vibration monitors do not
function properly. This situation has caused turbine damage and must be rectified.
j)
Turbine Supervisory System
The following supervisory measurements are made on the turbines: thrust bearing position,
eccentricity, casing expansion, relative expansion, and turbine speed by a digital electronic system.
Lack of bearing oil temperature monitors have caused failure of turbine bearings because of a
loss of oil cooling. This situation should be corrected.
k)
Feedwater Heating Controls
The condenser hotwell level and the levels in the feedwater heaters 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. Extraction number 9 does not have a check valve.
1)
Plant Alarm System
This is the original system which still operates in a satisfactory manner. The system is not
prioritized hence many alarms can appear for a single cascading failure. A standard, simple ISA
sequence is used for display and control of the lamps and the horn.
m)
Local Panels
Each local turbine panel contains pressure gages for main steam and each extraction steam
pressure as well as control water and lubrication oil pressure. The local generator panels contain
gages for generator frequency, hydrogen pressure and generator cooling.
5909-98A/No-3.DOC/I/17/96
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n)
Thermal Insulation Detector
The boiler furnaces tubewall insulation has deteriorated as has the air/flue gas duct system. Visual
examination has indicated that other plant systems also have deteriorated insulation. A portable
optical temperature detector would be a useful device in locating and determining missing or
deteriorating insulation.
5909-98A/No-3.DOC/1/17/96
31
3.5 AIR POLLUTION CONTROL
Emissions of particulates, sulfur dioxide (SO₂) and nitrogen oxides (NO₂) and the impact of these
emissions on ambient air quality are of concern to the power plants and the surrounding
communities. At the Ermakovskaya power plant dust collection equipment is provided to remove
a major portion of the fly ash from the flue gas before discharge. The following table shows the
concentrations of NO, and SO₂ in the flue gas for all boilers at the Ermakovskaya plant.
Boiler No.
NOx Concentration, g/Nm3
SO₂ Concentration, g/Nm³
Min.
Max.
Min
Max.
1A
0.833
0.9512
0.894
0.956
1B
0.654
0.890
0.667
0.854
2A
0.540
0.659
0.835
0.944
2B
0.692
0.742
0.803
0.994
3A
0.580
0.842
0.867
1.083
3B
0.566
0.735
1.107
1.210
4A
0.560
0.760
0.735
1.133
4B
0.623
0.715
0.995
1.345
5A
0.786
0.860
1.160
1.398
5B
0.694
0.760
1.285
1.599
6A
0.756
0.793
0.852
1.388
6B
0.652
0.721
0.902
1.291
7A
0.529
0.652
1.162
1.251
7B
0.649
0.726
1.034
1.109
8A
0.589
0.887
0.701
1.298
8B
0.762
0.958
0.762
0.896
Note: Measurements were made with "Eduiometer" instruments using methods developed by the
Thrizhanovsky ENIN Institute.
From this table it can be seen that the boilers from block No. 3 (3A and 3B) have one of the
lowest concentrations of NO₂, while it's SO₂ concentrations are slightly higher than the average.
Currently, there is no NO, or SO₂ control equipment installed at the Ermakovskaya Plant.
5909-98A/No-3.DOC/1/17/96
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In order to remove fly ash from the flue gas, Electrostatic Precipitators (ESP's) are used at the
Ermakovskaya power plant. The existing ESP's have 7.5 meter high plates, with 3 fields. The
maximum collection efficiency of these units, when firing Ekibastuz coal, is 97.5%. Due to the
deterioration of these units, the current collection efficiency is much lower. Because of lack of
mechanical system of replacing suspended electrodes and the general deterioration of the ESP
units, they need to be replaced with new units.
5909-98A/No-3.DOC/1/17/96
33
4.0
REHABILITATION PROGRAM
4.1
STEAM BOILERS REHABILITATION RECOMMENDATIONS
a)
Coal Pulverizers
It is recommended that the existing four high speed, horizontal shaft hammer mills per boiler be
replaced with four new larger medium speed vertical shaft roller mill pulverizers per boiler. This
will make it necessary to remove the existing hammer mills and associated equipment.
The following new equipment, will be required:
1)
Foundations (Reinforced Concrete and Steel Rafts)
2)
Pulverizers and Dynamic Classifiers with electric motor or hydraulic drive
3)
Coal Piping to Mills
4)
Gravimetric Coal Feeders and Electric Motor Drives (optional, recommended but
not mandatory. Not included in the cost estimate.)
5)
Hot Primary Air and Coal Piping and Valves
6)
Cold Tempering Air Piping and Valves
7)
Pulverizer Drives, Electrical Equipment etc.
8)
Misc. Drives for Feeders, Classifiers, With Switchgear, Controls, etc.
9)
Retain Existing Hot P/A Fans and Seal Air Fans
b)
Forced Draft (FD) and Induced Draft (ID) Fans
All fans should be performance tested and the results compared to the performance needed when
the pollution control equipment is installed. Then the decision can be made to either refurbish or
replace the fans. In the interim, the cost of refurbishment, foundation skids, etc. will be
recommended for addition to the budget for the FD fans. The cost of replacement will be added
for the ID fans when the fan requirement is established.
c)
Heating Surfaces/Wall Blowers and Sootblowers
Extended surface primary superheater and economizer tube banks will be retrofitted with in-line
centers, replacing the existing bare tube banks on staggered centers.
5909-98A/No-3.DOC/1/17/96
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It will be necessary to add sootblowers to the convection passes of both boilers to avoid fouling
of the extended surfaces. This is particularly important with the high ash of the Ekibastuz coals.
A full complement of wall and sootblowers will need to be installed on boiler 3a.
d)
Furnace Ash Hopper Tubing
The horizontal tubing in the Block 3 boiler furnaces hopper walls should be replaced with vertical
tubing to improve ash and slag evacuation, and to improve resistance to slag falls.
e)
Low NO, Burners
Low NO, burners should be installed on both boilers of Block No. 3. These will be internally
fuel/secondary air staged burners, preferably without the need for using bulk furnace air staging
(OFA), so as to avoid the need for substoichiometric furnace burner zone firing conditions and
associated corrosion and slagging problems.
f)
Tube Penetration Seals
Tube penetration seals of furnace and backpass roof tubes, and in backpass tube banks for
superheaters, reheaters, and economizers are leaking and must be refurbished and tightened.
g)
Air Heaters
Refurbish and repair the rotary, regenerative, bi-sector vertical shaft air heaters, including radial
and circumferential seals, cold end sectors of rotors, sootblowers, etc. as required.
h)
Condition Assessment of Pressure Parts
A boiler condition assessment should be done on furnace, SH, RH tubing and water/steam-cooled
thick-walled pressure parts; i.e., headers, desuperheater piping, integral piping etc.
An NDE examination of the pressure parts of one of the two boilers of Block 3 appears
warranted. Following a review of the findings, remedial action will be recommended.
i)
Furnace and Boiler Setting
Boiler refractory, insulation, casing (BRIC) should be refurbished as needed, for furnace vertical
walls, tube hopper slopes, furnace and backpass roof, two backpasses walls, boiler outlet fluegas
ducts and flyash hoppers.
5909-98A/No-3.DOC/1/17/96
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Improvements in Boiler Thermal Performance
a) General
Boiler thermal performance would improve following the implementation of rehabilitation
measures due to reduced air in-leakage, increased heat transfer surface, improved sootblowing,
improved air heater performance, reduced air heater leakage, improved coal pulverizer
performance, NDE of pressure parts and consequent repairs, improved F.D. and I.D. fan
performance, and new boiler feed pumps. The rehabilitated boilers will gain approximately 15
years in life extension.
b) Main Steam Output
Deficient boiler output currently restricts the plant to achieve full output. Maximum total steam
flow is approximately 843,000 kg/hr or about 89 percent of design rated Maximum Continuous
Rating (MCR). Following rehabilitation, output is anticipated to return to MCR (Total 950,000
kg/hr of two boilers).
c) Boiler Efficiency
Current boiler efficiency is 86-87 percent. Boiler efficiency (Lower Heating Value basis) is
anticipated to return the design to 91.8 percent following rehabilitation. This
is an improvement of 5-6 percent. However, the higher than design coal mineral matter content
(44% by wt. now, versus 39% of the design coal) will have an adverse effect on boiler efficiency.
d) Ekibastuz Coal Cleaning
We attach in the Appendix I a concise coal slagging, fouling, erosion and ash corrosion propensity
study, which clearly indicates the merits of coal mineral matter reduction for the improvement of
the present serious furnace slagging problem.
4.2
STEAM TURBINE GENERATOR REHABILITATION RECOMMENDATIONS
Based on the assessment of the current performance and condition of the block 3 steam turbine
the following major replacements and modifications are recommended:
a)
Steam Turbine
Block 3 turbine has experienced various problems over the years. They still continue, and 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 plan be made to replace the main turbine, complete with ancillary systems and
components, from main steam stop valve inlet to exhaust hood connection to main condenser,
5909-98A/No-3.DOC/1/17/96
36
including instrumentation and controls, control valves, lube oil system, steam seal system,
extraction steam system, heater drain system, and interconnecting piping.
The replacement turbine for the block 3 block should be a nominal 310 MW new unit type K-310-
240-3 which has a turbine heat rate of 7988 Btu/kWh (2013 kcal/kWh). Installation of this new
turbine will not only resolve the current problems due to deterioration of the existing turbine but
will improve the operating performance of the unit. Compared to how the unit can operate today
the following are the output and heat rate improvements:
Current
New
Improvement
Unit
%
Output, MW
280
310
30
10.7
Heat Rate, kcal/kWh
2222
2013
209
9.4
Therefore, the new unit would operate with a turbine cycle efficiency of 42.7%.
b)
Generator
At this point it appears that the existing generator can be retained since the power will only
increase about 3% over the 300 MW original rating, and plant personnel indicated that the
original generator design allowed to increase power to 340 MW in the past. It is anticipated that
a small increase of the hydrogen coolant pressure will be required. The existing generator must
be inspected, and the necessary repairs and refurbishment should be accomplished. The generator
manufacturer should be asked to verify that the generator can meet the new requirement (310
MW). If not, then the generator must be replaced with a new 310 MW generator.
c)
Turbine Sliding Support
Installation of the new turbine will undoubtedly solve the thrust bearing and vibration problems.
However, based on modifications needed for the support arrangement between the new HP and
IP turbine shells, it is recommended that the design of the turbine support mounts be reviewed by
the turbine manufacturer (and if necessary redesigned) to eliminate or prevent any future turbine
shell alignment problems.
d)
NDE Equipment
Since at present no replication type creep monitoring equipment exist at the plant it is
recommended that such equipment as well as boroscopes be purchased as soon as possible in
order to better be able to predict metal degradation and detection of minor cracks in thick walled
5909-98A/No-3.DOC/1/17/96
37
pressure parts of the 8 turbines (and 16 boilers). This equipment should be used between now
and the time of the actual replacement of the Unit 3 turbine.
e)
Water Induction Protection
It is recommended that the steam cycle steam and water systems; e.g., extraction steam, heater
drains, etc. be reviewed for compliance with standard industry practice and turbine manufacturer's
recommendations for water induction protection. Any system or component which does not
incorporate appropriate water induction features should be upgraded to avoid future water
induction incidents.
Water induction protection features could be in the form of an automatic motor operated shutoff
valve and non-return valve in the extraction line if a heater is not installed in the condenser neck.
If a heater is located in the condenser neck, it may be feasible to install an automatic heater bypass
in the condensate system to prevent water backup into the extraction line in the event of
condensate leakage into the steam side of the heater.
f)
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, an adequate inventory of spare parts for the upgraded (and existing) equipment be
established.
4.3 AUXILIARY PLANT SYSTEMS
Based on the assessment of the current condition of the plant auxiliary equipment the following
additional modifications and replacements are recommended:
a)
Condenser
Replace previously plugged tubes.
Replace existing leaking tubes.
Correct existing air inleakages and institute a more formal air inleakage detection
program to systematically detect and eliminate air ingress into the vacuum space of
the condenser.
Retrofit circulating water side of condenser with sponge ball (Taprogge type) tube
cleaning system
5909-9RA/No-3.DOC/1/17/96
38
b)
Feedwater and Condensate System
Replace the feedwater heaters (single string of low pressure heaters and two
strings of high pressure heaters) corresponding to new design conditions based on
extraction points on the replacement turbine. The new heaters should be designed
with optimized TTD and DCA.
The steam generator feedpumps (both turbine driven and motor driven) should be
replaced with modern more efficient ones.
The condensate polishing system should be replaced.
The feedwater booster pumps, condensate and condensate booster pumps should
be maintained, repaired or replaced as part of the plant's routine maintenance
activities. These pumps and the existing drain pumps should be reviewed to
establish compatibility and/or required modifications for use with the new revised
steam turbine cycle.
c)
Circulating Water Pumps
Add new filters to the lubrication water system of the rubber bearings of the
circulating water pump shafts.
4.4 PLANT INSTRUMENTATION AND CONTROLS
Recommended action involves the repair and replacement of the Block 3 instrumentation and
controls, as necessary, plus the implementation of additional I&C improvements. The following
plant instrumentation and control improvements are recommended, based on an assessment of
Block 3, and discussions with cognizant plant engineering management.
1.
Four high temperature O₂ analyzers, (in-situ type, positioned near the furnace exit planes)
to achieve optimum combustion efficiency.
2.
Good quality portable combustion analyzer (CO, SO2, NO,, combustibles)
3.
Replace portions of the boiler control system with modern single loop controllers to
achieve automatic control of the steam pressure and temperature throughout the load
range.
4.
NO, emissions monitoring equipment for the boiler to determine the effectiveness of NO,
reduction initiatives.
5909-98A/No-3.DOC/1/17/96
39
5.
Particulate emissions monitoring for boiler flue gas to determine the effectiveness of the
scrubbers and electrofilters.
6.
SO₂ emissions monitoring equipment for the boiler.
7.
A heat spy for measuring heat leakages and electrical hot spots.
8.
Non-contact type flow meters to measure mazut consumption by the boiler.
9.
Refurbish the existing superheat and reheater attemperator control valves.
10.
New turbine control and supervisory system including turbine stress monitor.
11.
Moisture monitoring equipment to determine the quantity of moisture in the boiler flue gas
in order to perform combustion calculations.
The above list was developed during the condition assessment of Block 3 and is considered
necessary for rehabilitation and modernization. Implementation of these recommendations will
extend the plant life and yield an improvement in reliability and availability and reduce
maintenance costs.
4.5
AIR POLLUTION CONTROL RECOMMENDATIONS
Ermakovskaya 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 Ermakovskaya 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. In addition, nitrogen oxide control measures such as low NO, burners and overfire air
ports will need to be retrofitted in the boiler.
As stated in the Boiler Rehabilitation Recommendation section (4.1), new low NO, burners,
preferably without overfire air should be installed. A total of 24 burners (12 per boiler) will be
required. These burners will reduce the NO, emissions from the block when used in conjunction
with or without the overfire air system. The LNBs together with the pulverizer dynamic
classifiers will also help improve combustion efficiency of the boilers.
No sulfur dioxide control (removal) equipment is recommended at this time. The coal currently
being fired (Ekibastuz), is a very low sulfur coal. It only contains approximately 0.6% sulfur. If
the coal being fired at the plant changes to a high sulfur coal, a Flue Gas Desulfurization System
(FGD) may be required to handle this problem.
5909-98A/No-3.DOC/1/17/96
40
In order to increase the ash collection efficiency of the ESP's, modifications need to be performed.
The current ESP's should be replaced with new units with 5 field and 12 meters high plates. In
addition, a new control system for the ESP's will also help to increase the collection efficiency.
Burns and Roe has included the cost of replacing the existing ESP's with the new ESP's (5 field
and 12 meter high plates) in the Block No. 3 rehabilitation cost estimates.
4.6
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,
843,000
950,000
12.7
kg/HR
Boiler Efficiency, LHV
86-87
91.8
5~6
basis %
Turbine/Generator
280
310
10.7
Output, MWe
Heat Rate, Kcal/kWh
2222
2013
9.4
Plant Life Extension
-
15 years
Plant Capacity Increase
280
310
10.7
Increase in Plant
-
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 block by
increasing its availability and reliability, decreasing Operating and Maintenance costs, and
extending the life of the block. 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 block and should allow the block 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
5909-98A/No-3.DOC/1/17/96
41
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 plant 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 as it is already 25 years in operation (from 1970), it
will require substantial capital investment. The plant rehabilitation will also result in reducing the
potential cost of replacement power to be purchased when Block 3 plant were to be shutdown
due to unplanned (forced) outages.
One additional benefit of Block 3 rehabilitation is an increase in plant availability and reliability
due to major renovation and upgrade of critical plant components such as boilers, turbines,
auxiliary plant equipment and Instrumentation and controls upgrades. It is estimated that the
Block 3 availability and reliability will improve by 10 to 12 percent as a result of the proposed
Block 3 rehabilitation.
5909-98A/No-3.DOC/1/17/96
42
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
Replacement of existing 8 Hammer Mills with 8 new Vertical Spindle Roller Mills
Installation of New Rotating (Dynamic) Classifiers
Replacement of Boiler Setting (refractory, insulation & casing) for 2 Boilers
Replacement of two (2) Boiler Convective Heating surfaces with extended surface
Repair of (4) Air Heaters
Installation of New Low NO, Burners and overfire air nozzles
Replacement of two (2) Ash Hoppers with vertical tube walls
Repair of two (2) Forced Draft Fans
Replacement of two (2) Induced Draft Fans
Retrofit of a total of 192 furnace wall blowers and retractable sootblowers (two boilers)
Installation of 160 Tubewall Blowers
Repair or replace boiler tube penetration seals
Replacement of 10% of the steam system valves
Replacement of Steam Turbine with new 310 MW turbine
Installation of Turbine Extraction Valves and Water Induction Protection
Retubing 10% of Condenser Tubes
Replacement of Feedwater Heaters
Replacement of two (2) Boiler Feed Pumps
Installation of a Condenser Cleaning System
Installation of a Demineralizer System and Condensate Polishers
Procurement of new NDE equipment
Replacement of two (2) Electrostatic Precipitators
Install Emissions and Air Flow Monitoring Equipment
Install Boiler and turbine Monitoring Equipment
Miscellaneous Instrumentation and Controls System Upgrades
Replacement of 28 km of Power Cable
Replacement of 80 cubicles of MCC's
Replacement of Auxiliary Switchgear
The project cost estimate is conceptual in nature, and was based on information obtained during
Burns and Roe's site visit in March 1995.
5909-98A/No-3.DOC/1/17/96
43
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 scope of work 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.
5909-98A/No-3.DOC/1/17/96
44
CONCEPTUAL COST ESTIMATE
REHABILITATION OF 300 MW BLOCK No. 3
COAL FIRED POWER PLANT ERMAKOVSKAJA, KAZAKSTAN
ITEM
LABOR
WESTERN
LOCAL
TOTAL
COST $
MAT'L $
MAT'L COSTS
COST
BOILERS
Remove Existing Burners (12 per Boiler 24 Total)
85,200
2,600
87,800
Install New Low NOx Burners & OFA System
159,100
5,940,000
152,500
6,251,600
Remove Existing Hammer Mills (4 per Boiler 8 Total)
74,400
2,200
76,600
Remove Existing Hammer Mill Foundations
53,800
1,600
55,400
Remove PA/PC Ductwork (2 Units)
84,600
2,500
87,100
Install New Roller Mill Foundations (8)
55,800
31,300
87,100
Install New Roller Mills (8)
194,000
2,400,000
77,800
2,671,800
Install New Classifiers (8 Total)
158,600
680,000
25,200
863,800
Install New PA/PC Ductwork (2 Units)
127,200
350,000
14,300
491,500
Boiler Refractory, Insulation, Lagging & Casing Repair (2 Units)
178,800
1,800,000
59,400
2,038,200
Tube Penetrations & Seals (2 Units)
77,400
480,000
16,700
574,100
Dismantle Horizontal Conv, SH, Econo Tube Banks (2 Units)
164,400
4,900
169,300
Install New Extended Surface for Mat'l Removed Above (2 Units)
229,200
7,100,000
146,600
7,475,800
Replace Sootblowers (16 per Unit 64 Total)
131,500
480,000
18,300
629,800
Repair Air Heaters (2 per Boiler 4 Total)
157,200
1,320,000
44,300
1,521,500
Repair Forced Draft Fans (1 per Unit 2 Total)
55,400
54,300
109,700
Remove Old Induced Draft Fans (2 Total)
26,400
800
27,200
Replace Induced Draft Fans (2 Total)
79,900
1,200,000
38,400
1,318,300
Remove Existing Boiler Ash Hoppers
41,900
1,300
43,200
Install New Boiler Ash Hoppers
50,800
440,000
14,700
505,500
Install Tubewall Blowers (80 per Boiler 160 Total)
203,200
2,250,000
73,600
2,526,800
Perform Non-Destructive Testing (Allowance)
50,000
50,000
Perform a Draft Plant Assessment on a Boiler Train (Allowance)
50,000
50,000
TOTAL BOILER WORK
2,244,500
18,500,000
628,200
21,372,700
TURBINE GENERATOR
Remove Existing Turbine & Piping
219,400
0
6,600
226,000
Install New 310 MW Turbine & Accessories (No Generator)
429,600
16,577,000
340,100
17,346,700
Install Turbine By-Pass System
128,200
850,000
29,300
1,007,500
Repair Extraction & Drain Systems
127,200
1,200,000
39,800
1,367,000
Procure NDE Equipment
0
30,000
0
30,000
Modify Turbine Pedestal
134,100
0
21,000
155,100
Repair & Replace 10% of Steam System Valves
79,200
1,050,000
33,900
1,163,100
TOTAL TURBINE WORK
1,117,700
19,707,000
470,700
21,295,400
45
01
é
SHEET 1 OF 3
CONCEPTUAL COST ESTIMATE
REHABILITATION OF 300 MW BLOCK No. 3
COAL FIRED POWER PLANT ERMAKOVSKAJA, KAZAKSTAN
ITEM
LABOR
WESTERN
LOCAL
TOTAL
COST $
MAT'L $
MAT'L COSTS
COST
FEEDWATER SYSTEM
Modify Condenser Neck/Turbine Exhaust
23,100
50,000
2,200
75,300
Install New Filters for Circ Water Pumps
15,700
20,000
1,100
36,800
Remove Existing Boller Feed Pumps
39,800
1,200
41,000
Install New Boller Feed Pumps
107,500
779,640
26,600
913,740
Remove Existing Feedwater Heaters
68,300
2,000
70,300
Install New Feedwater Heaters
184,900
1,800,000
39,700
2,024,600
Retube Condenser
214,400
586,000
24,000
824,400
Install Condenser Cleaning System
188,900
1,300,000
29,800
1,518,700
Install Demin System & Polisher
123,700
600,000
21,700
745,400
TOTAL FEEDWATER SYSTEM WORK
966,300
5,135,640
148,300
6,250,240
INSTRUMENTATION & CONTROLS
Install Emissions Monitoring Equipment
64,500
565,000
12,600
642,100
Install Air Flow Monitoring Equipment
47,300
285,000
6,600
338,900
Install Boiler Monitoring Equipment
55,000
413,000
9,400
477,400
Install Turbine Monitoring Equipment
42,700
210,000
5,100
257,800
Miscellaneous Instrumentation & Controls
38,000
130,500
3,400
171,900
TOTAL INSTRUMENTS & CONTROLS
247,500
1,603,500
37,100
1,888,100
ELECTRICAL SYSTEM
Install New Power Cable (28 KM)
168,000
284,400
13,600
466,000
Remove & Replace Existing MCC's (80 cubicles)
64,400
185,900
7,500
257,800
Replace Auxilliary Switchgear (65 cells)
83,300
238,000
9,600
330,900
Replace Auxilliary Transformer (40 KV/6.3/6.3)
116,700
625,000
22,300
764,000
Replace Excitation Transformers (1000 KVA)
12,600
46,000
1,800
60,400
Replace Excitation System
43,300
125,000
5,000
173,300
TOTAL ELECTRICAL WORK
488,300
1,504,300
59,800
2,052,400
ENVIRONMENTAL SYSTEM
Remove Existing Precipitators
73,100
2,200
75,300
Install New Electrostatic Precipitators
265,200
5,627,500
147,300
6,040,000
TOTAL ENVIRONMENTAL WORK
338,300
5,627,500
149,500
6,115,300
SUBTOTAL
5,402,600
52,077,940
1,493,600
58,974,140
Freight
4,101,200
Contingency (10%)
5,887,400
TOTAL COST OF REHABILITATION
68,962,740
$/KW
222
ALL COSTS ARE SHOWN IN 1995 DOLLARS
01/16/96
SHEET 2 OF 3
IF THIS PROJECT WERE TO BE CONSTRUCTED IN THE USA
THE FOLLOWING ADDITIONAL COSTS WOULD APPLY:
DIRECT COSTS FROM PREVIOUS PAGE
68,962,740
Engineering Costs
3,538,448
Construction Management Costs
1,769,224
Start-Up Costs
1,179,483
Construction Equipment Costs
1,750,000
Interest During Construction
5,517,019
Escalation
6,617,353
TOTAL COST INCLUDING THE ITEMS ABOVE
$/KW288
89,334,268
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
47
01/12/96
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.
5909-9&A/No-3.DOC/I/17/96
48
CONSTRUCTION SCHEDULE FOR THE REHABILITATION OF THE ERMAKOVSKAYA PLANT BLOCK NO. 3
Tasks
Month 1
Month 2
Month 3
Month 4
Month 5
Month 6
Month 7
Month 8
Month 9
BOILER WORK (2 Boilers)
Remove Boiler Mechanical Components (Burners, Tubes, etc.)
Remove Boiler Auxiliary Equipment (Mills, Fans, etc.)
Remove Mill Foundations
Install New Mech. Components Including Heat Transfer Surfaces
Install New Mills and Auxiliaries Including Fans
Repair Boiler Casing, Refractories, Insulation, etc.
TURBINE GENERATOR
Remove Existing Turbine and Auxiliaries
Replace Recommended Piping System and Valves
Install New Turbine and Auxiliaries
AUXILIARY PLANT SYSTEM
Replace Feedwater Pumps
Replace Feedwater Heaters
Condenser Modification (Neck, Tubing, Tube cleaning, etc.)
Replace Condensate Polishing System & Other Piping and Valves
ENVIRONMENTAL
Replace Electric Precipitators
INSTRUMENTATION
Install Emissions and Air Flow Monitoring Equipment
Install Boiler and Turbine Monitoring Equipment
Misc. Instrumentation & Controls System Upgrades
ELECTRICAL WORK
Repair and Replace Existing MCC's
Power Cable & Misc. Electrical Work
STARTUP AND CHECKOUT
49
Page 1
CONSTRUCTION SCHEDULE FOR THE REHABILITATION OF THE ERMAKOVSKAYA PLANT BLOCK NO. 3
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
Month 25
50
Page 2
7.0
EVALUATION OF EMAKOVSKAYA BLOCK 2 REHABILITATION
Burns and Roe engineers reviewed the plans for rehabilitation of Ermakovskaya Block 2 during
their site visit. Block 2 was built and commissioned in 1969. Since then the turbine has been in
operation for 184,400 hours, while the boiler has logged 164,800 operational hours to date. Due
to this relatively large amount of operational time, this block has had numerous boiler and turbine
failures. In 1994, the boiler had 28 forced outages. Most of these were furnace tube failures. In
the same year, the turbine had 6 forced outages. These outages were caused by defective valves,
vibration problems, and control system problems. Thus, it is evident that this Block is in dire need
of rehabilitation. The Block 2 renovation plan as described by the plant engineers is as follows:
Item
Description
A.
Boilers (2) and Auxiliaries
1.
Replacement of approximately 70 percent of the furnace tubewall heating surface.
2.
Repair/replacement of the boiler setting (boiler tubewall refractory, insulation, and
casing).
3.
Replacement of boiler feedpumps.
B.
Turbine and Auxiliaries
1.
Replacement of existing steam turbine (300 MW nameplate rating) with new
turbine (310 MW nameplate rating) with the same throttle conditions. (Same
mainsteam pressures, temperatures, and steam flows)
2.
Replacement of turbine piping adjacent to turbine and pedestal (steam, feedwater,
condensate, cooling water, lubricating oil, etc.)
3.
Condition assessment of high temperature, high pressure parts such as steam leads,
high pressure steam and feedwater lines, etc.
4.
Replacement of high pressure and low pressure feedwater heaters (two strings of 3
high pressure heaters each, and one string of 5 low pressure heaters).
5.
Replacement of turbine drainage equipment.
C.
Balance of Plant
1.
Replacement of feedwater makeup treatment plant.
5909-98A/No-3.DOC/1/17/96
51
2.
Replacement of auxiliary transformers (TPDHC-40000/20/b,3/6,3)
3.
Replacement of auxiliary switchgear (65 cells)
4.
Replacement of electrical distribution motor control centers. (80 @380 VAC 50
Hz).
5.
Replacement of 4 @1000 kVA excitation transformers.
6.
Replacement of excitation system.
7.
Replacement of 28 km of power cable.
D.
Environmental
1.
Replacement of existing electrostatic precipitators (3 field X 7 meter high plates)
with new units (5 field X 12 meter high plates).
E.
Instrumentation and Controls
1.
Replacement of the current control system with a modern Distributed Control
System (DCS).
Currently, the net heat rate and capacity factor for block 2 are estimated at 2180 kcal/KWh and
39.5% respectively. It is anticipated that after the rehabilitation these indicators will improve
substantially. This rehabilitation will also help reduce fuel consumption due to the recovery of
efficiency losses from the deterioration of the equipment and will improve block 2 plant
availability and reliability.
The rehabilitation of Ermakovskaya Block 2 was discussed with cognizant Ermakovskaya
engineering management at the Plant. Burns and Roe generally concurs with these plans for the
rehabilitation of Block 2, which will largely restore the output, efficiency and availability lost due
to plant deterioration.
5909-98A/No-3.DOC/1/17/96
52
APPENDIXI
ERMAKOVSKAYA BOILER FURNACE
SLAGGING COMPUTER ANALYSES
Ermakovskaya Boiler Furnace Slagging Computer Analyses
Burns and Roe was requested by Kazakenergo to make recommendations for the amelioration of the
rather serious lower furnace slagging problem of the Ermakovskaya boilers. It was also suggested
that our approach to the problem should include consideration for variable coal mineral matter (ash)
content and variation of the chemical composition of Ekibastuz coal.
Burns and Roe conducted the furnace slagging study using five different ash contents of the coal
ranging from 44% to 37% ash. The data for the five cases are shown in the following tables.
Technical Data:
Ekibastuz coal [now fired], proximate analyses:
Ekibastuz Coal
#1
#2
#3
#4
#5
Ash
% by weight
49
46
43
40
37
Water "
7
6
7
6
6
VM
66 99
12
13
13
14
14
FC
66 99
32
35
37
40
43
Total
100
100
100
100
100
Ekibastuz coal [now fired], ultimate analyses:
Ash
% by weight
49
46
43
40
37
Water "
7
6
7
6
6
Carbon " "
34
36.3
38
42
47
Hydrogen
3
3.1
3
4
4
Nitrogen
1
0.9
1
1
1
Sulfur 66 99
1
0.7
1
1
1
Oxygen" " [by diff.]
5
7
7
6
4
Total
100
100
100
100
100
LHV range 14 to 16 MJ/kg (3343 to 3821 kcal/kg or 6018 to 6878 BTU/lb)
12/28/95:APP_1.WPD
2
54
HHV kcal/kg
3545
3700
3778
3860
4067
BTU/lb
6380
6658
6800
6950
7320
Now fired coal mineral matter chemical analyses:
Ekibastuz Coal
#1
#2
#3
#4
#5
SiO₂
% by weight
55
60.00
57
60
60
Al₂O₃ 66 93
29
29.00
29
28
30
Fe₂O₃ "
11
6.50
9
7
5
TiO₂
"
1
1.00
1
1
1
CaO 66 99
2
1.70
2
2
2
MgO ""
0.7
0.70
0.7
0.7
0.7
K₂O
""
0.7
0.65
0.7
0.7
0.7
Na₂O ""
0.3
0.30
0.3
0.3
0.3
SO₃
"
0.3
0.15
0.3
0.3
0.3
Total
100
100
100
100
100
Grindability Indices:
Russian Kpo = 1.3
HGI's assumed:
70
66
68
66
66
Fusibility temperatures of ash [assumed reducing atm.]:
Initial Deform. °C
1145
1200
1150
1180
1400
Softening
°C
1300
1400
1350
1450
1500
Flow
°C
1350
1500
1400
1500
1550
12/28/95:APP_1.WPD
3
Slagging Process Description of the Pn-950-255/545 Boiler
Slagging type furnace tubewall deposits have always been encountered with the firing of
Ekibastuz coal, but the rate of deposition at any given load has increased due to the deteriorated
condition of the boilers. The heavier deposits are located in the furnace burner zone, around the
burners (eyebrow type deposits probably). In addition, the slagging deposits are also located in
the corners of the furnaces, in the maximum furnace heatflux zone above the top horizontal row
of burners, and at the upper furnace exit plane including the bottom part of the pendant radiant
superheater platens. The full load furnace adiabatic flame temperature is estimated to be 1550 °C
and the furnace exit gas temperature [FEGT] at the same load is estimated to be approx. 1250 °C.
The slagging process in the subject furnaces is influenced [among other factors], by the
characteristics of the coal and its mineral matter chemical composition, the local oxidizing and/or
reducing atmospheres, the combustion process, the pulverized coal fineness, the design of the
furnace tubewall, and by the design of the burners, etc.
The tubewall deposition process starts with slag pieces of 100 to 200 mm size adhering to the
fireside tube surfaces. These are loose deposits, relatively easily dislodged and fall to the furnace
bottom and are removed by the bottom ash handling system. However, from time to time, pieces
of slag on the tubewalls increase to larger sizes [500 to 1000 mm] and then fall to the furnace
bottom into the tube hopper. Here they accumulate together with other slag pieces and some
flyash particles. The slag accumulation proceeds gradually as the furnace tube hopper walls are
covered by the slag accumulation, the furnace heat absorption falls for the same amount of
furnace heat input, the furnace gas temperatures increase, thereby increasing the slag deposition
rate on the tubewalls and also the furnace bottom slag accumulation. The slagging process
continues until operators are forced to trip the firing.
According to plant personnel, the main reasons for the furnace slagging problem are:
Deterioration in the Ekibastuz coal quality. Ash content increased from the design 38.7%
by weight to a maximum of 59 %, LHV decreased from design of 3710 kcal/kg to approx.
3300 kcal/kg, and some changes occured over the years in the coal mineral matter
chemical composition.
Furnace tube hopper construction [meandering horizontal tubebands and tube hopper
opening too narrow] and bottom ash removal system has inadequate capacity for the
removal of the increased quantities of bottom ash.
Insufficient burner zone height, thus resulting in rather high burner zone heat release
rates. The distance between the centerline of horizontal burner rows should be increased.
Possible local reducing atmosphere furnace conditions in the burner zone.
12/28/95:APP_1.WPD
4
56
Unequal fuel and secondary [combustion] air distribution between burners.
Insufficient coverage by furnace tubewall steam sootblowers. The existing cleaning
equipment is not able to effectively remove slag accumulations around the burners and
from the furnace corners.
Burns and Roe analyzed the cases using an inhouse computer program, which assesses the
slagging, fouling, erosion and corrosion propensity of coal mineral matter, [ash] together with a
correlation that aims to establish furnace cleanability for a given coal mineral matter. Please see
the attached computer input/output sheets and 2 pages of graphs for each of the cases. The
graphs illustrate the Halfinger Furnace Cleanability correlation. The correlation uses the ash
content (lb/MMBTU), the base/acid ratio and the ash softening temperature, to arrive at a furnace
cleanability assessment. The horizontal line drawn from the calculated Base/Acid ratio is
connected with the calculated ash input [lb/million BTU]. The ash inputs (ash contents) are
plotted both on the above referenced as well as the bottom horizontal lines. Please ignore the
Base/Acid ratio of 1.2, this is an incidental baseline onto which the furnace ash "inputs"
[lb/million BTU] have been plotted. The lines of specific slope represent increasing ash inputs
[lb/million BTU] i.e. the higher the value of ash input the less steep the slope.
The horizontal line drawn from the calculated Base/Acid ratio is intersected with the specific
sloping line originating from the calculated ash input [lb/million BTU]. The intersection point is
transferred to the next graph, continued as a horizontal line and intersected with a vertical line
originating from the inputted Ash Softening Temperature. The final intersection falls into
a"furnace cleanability assessment" zone. The zone happens to be worse than doubtful in most of
our referenced cases, due to the very high "ash input" [lb/million BTU] values. Either a
reduction of "ash inputs" or an increase of the Ash Softening Temperatures would bring the
cleanability assessment into more favorable cleanability zones. For all of the runs, the
cleanability assessment is worse than doubtful or doubtful, because of the high ash content.
A quick review of the results clearly points to the fact that for all variations in coal mineral
matter content and chemical composition of the mineral matter, all of the slagging indices
indicate a low or medium slagging propensity, except the ash content (lbs/MMBTU or
kg/million kcal). That is, if the coal mineral matter content could be reduced by some
physical or chemical means, prior to firing, then the slagging problem of the
Ermakovskaya boiler furnaces would be substantially reduced. This is a conclusion which
has already been made without reviewing the results of these computer calculations, by the
GRES technical personnel. Nevertheless, the results do seem to reinforce that conclusion.
12/28/95:APP_1.WPD
5
CALCULATIONS OF COMMON ASH
SLAGGING, FOULING, EROSION AND ASH CORROSION INDICES
AND REDUCING ATM. ASH FUSION TEMPERATURES
Date:
16-Nov-95
INPUT SHEET:
PAGE 1
Coal Name:
Ekibastuz 1
As Received Coal
Ultimate Analysis
Ash Analysis
Carbon
36.30
SiO2
60.00
Hydrogen
3.10
A1203
29.00
Sulfur
0.70
Fe203
6.50
Nitrogen
0.90
CaO
1.70
Oxygen
7.00
MgO
0.70
Ash
46.00
Na20
0.30
Moisture
6.00
K20
0.65
TiO2
1.00
Sum
100.00
P2O5
0.00
SO3
0.15
As Received Coal
Sum
100.00
Proximate Analysis
Fixed Carbon
35
Volatiles
13
Ash
46
Moisture
6
Sum
100.00
Hardgrove Grindability Index (HGI)
66
HHV (Btu/lb)
6658
Red. Atmos. Initial Deformation Temp.- - F
2192
Red. Atmos. Softening Temp. - F
2552
Red. Atmos. Fluid Temp. - F
2732
* Note: Analysis does not total 100%
50
CALCULATIONS OF COMMON ASH
SLAGGING, FOULING, EROSION AND ASH CORROSION INDICES
AND REDUCING ATM. ASH FUSION TEMPERATURES
OUTPUT SHEET:
PAGE 2
Coal Name:
Ekibastuz
Ash Nature:
Bituminous
SLAGGING INDICES:
Value
Rating
Base/Acid Ratio
0.11
Low
Slagging Factor (Rs) (After Winegartner)
0.08
Low
Slagging Factor (Rs) (After Nolte & Horney)
0.03
Low
T250 Temperature - F
By Method of Nicholls and Reid
2878
Low
By Method of Watt and Fereday
2809
Low
Halfinger Furnace Cleanability
NA
Doubtful
Silica to Alumina Ratio
2.07
Low
Iron to Calcium Ratio
3.82
Low
% Calcium in Ash
1.70
Low
Ash Content (As Received) - Lbs/MMBtu
69.09
Severe
Red. Atmos. Initial Deformation Temp.- - F
2192
Medium
Red. Atmos. Softening Temp. - F
2552
Low
Red. Atmos. Fluid Temp. - F
2732
Low
Delta (ID to F) Temp. - F
540
Low
Calc. Red. Atmos. Initial Deformation Temp. - F
2782
Low
Calc. Red. Atmos. Softening Temp. - F
2621
Low
Calc. Red. Atmos. Fluid Temp. - F
2740
Low
Calc. Delta (ID to F) Temp. - F
42
High
Furnace Design Parameter: Max. Allowable
Btu Input/Furn. Plan Area - Btu/Hr/Sq ft
1700000
NA
FOULING INDICES:
Value
Rating
Fouling Factor (Rf) (After Winegartner)
0.03
Low
Fouling Factor (Rf) (After Nolte & Horney)
0.05
NA
% Sodium in Ash
0.30
Low
Sodium Modifier
1.70
Higher
% Ash in Dry Coal (Ash Contains
0.30 % Na20)
48.94
NA
Ash Sodium plus Potassium Content in
Dry Coal (in Equivalent % Na20)
0.36
Medium
EROSION INDICES:
Value
Rating
Silica and Alumina in Ash - %
89.00
Severe
59
Ash Loading - Lbs/MMBTu
69.09 I Severe
Max. Allowable Gas Velocity - Ft/Sec.
7.58 I NA
Note: When several indices are applied to the same coal, they often
do not predict the same results.
NA: Not applicable
60
CALCULATIONS OF COMMON ASH
SLAGGING, FOULING, EROSION AND ASH CORROSION INDICES
AND REDUCING ATM. ASH FUSION TEMPERATURES
OUTPUT SHEET:
PAGE 3
COAL ASH CORROSION INDICES:
Value
Rating
Hardgrove Grindability Index (HGI)
66
Low
FC/VM
2.69
Medium
Alkalies/Alkaline Earth Ratio
0.40
Medium
Alkalies/CaO Ratio
0.56
Medium
Fe in Ash
6.50%
Medium
Sulfur
0.70%
Low
Sulfur/Alkaline Earth Ratio
0.29
Medium
61
Acid/Base Ratio VS. Ash Content
1.4
24 6 8 10121416182 02224262830
1.2
1
32
34
Base/Acid Ratio
0.8
36
0.6
0.4
0.2
2 68101214161820222426
0
0
20
40
60
80
Ash Content (As Received) - lbs/MMBTU
Furnace Cleaning Assessment
40
30
Ash Content (As Received) - lbs/MMBTU
20
Doubtful
Poor
10
Average
Good
0
1600.000
1800.000
2000.000
2200.000
2400.000
2600.000
2800.000
Ash Softening Temp, H=W Reducing - F
CALCULATIONS OF COMMON ASH
SLAGGING, FOULING, EROSION AND ASH CORROSION INDICES
AND REDUCING ATM. ASH FUSION TEMPERATURES
Date:
16-Nov-95
INPUT SHEET:
PAGE 1
Coal Name:
Ekibastuz #2
As Received Coal
Ultimate Analysis
Ash Analysis
Carbon
34.00
SiO2
55.00
Hydrogen
3.00
A1203
29.00
Sulfur
1.00
Fe203
11.00
Nitrogen
1.00
CaO
2.00
Oxygen
5.00
MgO
0.70
Ash
49.00
Na20
0.30
Moisture
7.00
K20
0.70
TiO2
1.00
Sum
100.00
P205
0.00
SO3
0.30
As Received Coal
Sum
100.00
Proximate Analysis
Fixed Carbon
32
Volatiles
12
Ash
49
Moisture
7
Sum
100.00
Hardgrove Grindability Index (HGI)
70
HHV (Btu/lb)
6380
Red. Atmos. Initial Deformation Temp. - F
2093
Red. Atmos. Softening Temp. - F
2372
Red. Atmos. Fluid Temp. - F
2462
* Note: Analysis does not total 100%
64
CALCULATIONS OF COMMON ASH
SLAGGING, FOULING, EROSION AND ASH CORROSION INDICES
AND REDUCING ATM. ASH FUSION TEMPERATURES
OUTPUT SHEET:
PAGE 2
Coal Name:
Ekibastuz #2
Ash Nature:
Bituminous
SLAGGING INDICES:
Value
Rating
Base/Acid Ratio
0.17
Low
Slagging Factor (Rs) (After Winegartner)
0.19
Low
Slagging Factor (Rs) (After Nolte & Horney)
0.07
Low
T250 Temperature - F
By Method of Nicholls and Reid
2756
Low
By Method of Watt and Fereday
2689
Low
Halfinger Furnace Cleanability
NA
Doubtful
Silica to Alumina Ratio
1.90
Low
Iron to Calcium Ratio
5.50
Low
% Calcium in Ash
2.00
Low
Ash Content (As Received) - Lbs/MMBtu
76.80
Severe
Red. Atmos. Initial Deformation Temp. - F
2093
Medium
Red. Atmos. Softening Temp. - F
2372
Medium
Red. Atmos. Fluid Temp. - F
2462
Medium
Delta (ID to F) Temp. - F
369
Low
Calc. Red. Atmos. Initial Deformation Temp.- F
2577
Low
Calc. Red. Atmos. Softening Temp. - F
2485
Low
Calc. Red. Atmos. Fluid Temp. - F
2593
Low
Calc. Delta (ID to F) Temp. - F
16
High
Furnace Design Parameter: Max. Allowable
Btu Input/Furn. Plan Area - Btu/Hr/Sq ft
1700000
NA
FOULING INDICES:
Value
Rating
Fouling Factor (Rf) (After Winegartner)
0.05
Low
Fouling Factor (Rf) (After Nolte & Horney)
0.05
NA
% Sodium in Ash
0.30
Low
Sodium Modifier
2.00
Higher
% Ash in Dry Coal (Ash Contains
0.30 % Na2O)
52.69
NA
Ash Sodium plus Potassium Content in
Dry Coal (in Equivalent % Na2O)
0.40
High
EROSION INDICES:
Value
Rating
Silica and Alumina in Ash - %
84.00
High
Ash Loading - Lbs/MMBTu
76.80
Severe
Max. Allowable Gas Velocity - Ft/Sec.
4.53
NA
Note: When several indices are applied to the same coal, they often
do not predict the same results.
NA: Not applicable
CALCULATIONS OF COMMON ASH
SLAGGING, FOULING, EROSION AND ASH CORROSION INDICES
AND REDUCING ATM. ASH FUSION TEMPERATURES
OUTPUT SHEET:
PAGE 3
COAL ASH CORROSION INDICES:
Value I Rating
Hardgrove Grindability Index (HGI)
70
Low
FC/VM
2.67
Medium
Alkalies/Alkaline Earth Ratio
0.37
Medium
Alkalies/CaO Ratio
0.50
Low
Fe in Ash
11.00%
Medium
Sulfur
1.00%
Low
Sulfur/Alkaline Earth Ratio
0.37
Medium
64
Acid/Base Ratio vs. Ash Content
1.4
2 4 6 8 10121416182 02224262830
1.2
1
32
34
Base/Acid Ratio
0.8
36
0.6
0.4
0.2
2 6 8 101 0222426
0
0
20
40
60
80
100
Ash Content (As Received) - lbs/MMBTU
89
Furnace Cleaning Assessment
50
40
Ash Content (As Received) - lbs/MMBTU
30
20
Doubtful
Poor
10
Average
Good
0
1600.000
1800.000
2000.000
2200.000
2400.000
2600.000
2800.
Ash Softening Temp, H=W Reducing - F
CALCULATIONS OF COMMON ASH
SLAGGING, FOULING, EROSION AND ASH CORROSION INDICES
AND REDUCING ATM. ASH FUSION TEMPERATURES
Date:
16-Nov-95
INPUT SHEET:
PAGE 1
Coal Name:
Ekibastuz #3
As Received Coal
Ultimate Analysis
Ash Analysis
Carbon
38.00
SiO2
57.00
Hydrogen
3.00
A1203
29.00
Sulfur
1.00
Fe203
9.00
Nitrogen
1.00
CaO
2.00
Oxygen
7.00
MgO
0.70
Ash
43.00
Na20
0.30
Moisture
7.00
K20
0.70
TiO2
1.00
Sum
100.00
P2O5
0.00
SO3
0.30
As Received Coal
Sum
100.00
Proximate Analysis
Fixed Carbon
37
Volatiles
13
Ash
43
Moisture
7
Sum
100.00
Hardgrove Grindability Index (HGI)
68
HHV (Btu/lb)
6800
Red. Atmos. Initial Deformation Temp.- - F
2102
Red. Atmos. Softening Temp. - F
2462
Red. Atmos. Fluid Temp. - F
2552
# Note: Analysis does not total 100%
CALCULATIONS OF COMMON ASH
SLAGGING, FOULING, EROSION AND ASH CORROSION INDICES
AND REDUCING ATM. ASH FUSION TEMPERATURES
OUTPUT SHEET:
PAGE 2
Coal Name:
Ekibastuz #3
Ash Nature:
Bituminous
SLAGGING INDICES:
Value
Rating
Base/Acid Ratio
0.15
Low
Slagging Factor (Rs) (After Winegartner)
0.16
Low
Slagging Factor (Rs) (After Nolte & Horney)
0.06
Low
T250 Temperature - F
By Method of Nicholls and Reid
2811
Low
By Method of Watt and Fereday
2738
Low
Halfinger Furnace Cleanability
NA
Doubtful
Silica to Alumina Ratio
1.97
Low
Iron to Calcium Ratio
4.50
Low
% Calcium in Ash
2.00
Low
Ash Content (As Received) - Lbs/MMBtu
63.24
Severe
Red. Atmos. Initial Deformation Temp.- - F
2102
Medium
Red. Atmos. Softening Temp. - F
2462
Low
Red. Atmos. Fluid Temp. - F
2552
Low
Delta (ID to F) Temp. - F
450
Low
Calc. Red. Atmos. Initial Deformation Temp.- F
2656
Low
Calc. Red. Atmos. Softening Temp. - F
2537
Low
Calc. Red. Atmos. Fluid Temp. - F
2649
Low
Calc. Delta (ID to F) Temp. - F
7
High
Furnace Design Parameter: Max. Allowable
Btu Input/Furn. Plan Area - Btu/Hr/Sq ft
1700000
NA
FOULING INDICES:
Value
Rating
Fouling Factor (Rf) (After Winegartner)
0.04
Low
Fouling Factor (Rf) (After Nolte & Horney)
0.05
NA
% Sodium in Ash
0.30
Low
Sodium Modifier
2.00
Higher
% Ash in Dry Coal (Ash Contains
0.30 % Na20)
46.24
NA
Ash Sodium plus Potassium Content in
Dry Coal (in Equivalent % Na20)
0.35
Medium
EROSION INDICES:
Value
Rating
Silica and Alumina in Ash - %
86.00
Severe
Ash Loading - Lbs/MMBTu
63.24
Severe
Max. Allowable Gas Velocity - Ft/Sec.
10.83
NA
Note: When several indices are applied to the same coal, they often
do not predict the same results.
NA: Not applicable
CALCULATIONS OF COMMON ASH
SLAGGING, FOULING, EROSION AND ASH CORROSION INDICES
AND REDUCING ATM. ASH FUSION TEMPERATURES
OUTPUT SHEET:
PAGE 3
COAL ASH CORROSION INDICES:
Value Rating
Hardgrove Grindability Index (HGI)
68 Low
FC/VM
2.85
Medium
Alkalies/Alkaline Earth Ratio
0.37
Medium
Alkalies/CaO Ratio
0.50
Low
Fe in Ash
9.00%
Medium
Sulfur
1.00%
Low
Sulfur/Alkaline Earth Ratio
0.37
Medium
Acid/Base Ratio vs. Ash Content
1.4
2 4 6 8 10121416182 02224262830
1.2
1
32
34
Base/Acid Ratio
0.8
36
0.6
0.4
0.2
2 4 6 8 101214161820222426
0
0
20
40
60
80
Ash Content (As Received) - lbs/MMBTU
Furnace Cleaning Assessment
40
30
Ash Content (As Received) - lbs/MMBTU
20
Doubtful
Poor
10
Average
Good
0
1600.000
1800.000
2000.000
2200.000
2400.000
2600.000
2800.000
Ash Softening Temp, H=W Reducing - F
CALCULATIONS OF COMMON ASH
SLAGGING, FOULING, EROSION AND ASH CORROSION INDICES
AND REDUCING ATM. ASH FUSION TEMPERATURES
Date:
16-Nov-95
INPUT SHEET:
PAGE 1
Coal Name:
Ekibastuz #4
As Received Coal
Ultimate Analysis
Ash Analysis
Carbon
42.00
SiO2
60.00
Hydrogen
4.00
AI203
28.00
Sulfur
1.00
Fe203
7.00
Nitrogen
1.00
CaO
2.00
Oxygen
6.00
MgO
0.70
Ash
40.00
Na20
0.30
Moisture
6.00
K20
0.70
TiO2
1.00
Sum
100.00
P2O5
0.00
SO3
0.30
As Received Coal
Sum
100.00
Proximate Analysis
Fixed Carbon
40
Volatiles
14
Ash
40
Moisture
6
Sum
100.00
Hardgrove Grindability Index (HGI)
66
HHV (Btu/lb)
6950
Red. Atmos. Initial Deformation Temp. - F
2156
Red. Atmos. Softening Temp. - F
2642
Red. Atmos. Fluid Temp. - F
2732
* Note: Analysis does not total 100%
CALCULATIONS OF COMMON ASH
SLAGGING, FOULING, EROSION AND ASH CORROSION INDICES
AND REDUCING ATM. ASH FUSION TEMPERATURES
OUTPUT SHEET:
PAGE 2
Coal Name:
Ekibastuz #4
Ash Nature:
Bituminous
SLAGGING INDICES:
Value
Rating
Base/Acid Ratio
0.12
Low
Slagging Factor (Rs) (After Winegartner)
0.13
Low
Slagging Factor (Rs) (After Nolte & Horney)
0.05
Low
T250 Temperature - F
By Method of Nicholls and Reid
2863
Low
By Method of Watt and Fereday
2801
Low
Halfinger Furnace Cleanability
NA
Doubtful
Silica to Alumina Ratio
2.14
Low
Iron to Calcium Ratio
3.50
Low
% Calcium in Ash
2.00
Low
Ash Content (As Received) - Lbs/MMBtu
57.55
Severe
Red. Atmos. Initial Deformation Temp. - F
2156
Medium
Red. Atmos. Softening Temp. - F
2642
Low
Red. Atmos. Fluid Temp. - F
2732
Low
Delta (ID to F) Temp. - F
576
Low
Calc. Red. Atmos. Initial Deformation Temp.- - F
2693
Low
Calc. Red. Atmos. Softening Temp. - F
2574
Low
Calc. Red. Atmos. Fluid Temp. - F
2706
Low
Calc. Delta (ID to F) Temp. - F
13
High
Furnace Design Parameter: Max. Allowable
Btu Input/Furn Plan Area - Btu/Hr/Sq ft
1700000
NA
FOULING INDICES:
Value
Rating
Fouling Factor (Rf) (After Winegartner)
0.04
Low
Fouling Factor (Rf) (After Nolte & Horney)
0.05
NA
% Sodium in Ash
0.30
Low
Sodium Modifier
2.00
Higher
% Ash in Dry Coal (Ash Contains
0.30 % Na20)
42.55
NA
Ash Sodium plus Potassium Content in
Dry Coal (in Equivalent % Na20)
0.32
Medium
EROSION INDICES:
Value
Rating
Silica and Alumina in Ash - %
88.00
Severe
Ash Loading - Lbs/MMBTu
57.55
Severe
Max. Allowable Gas Velocity - Ft/Sec.
9.64
NA
Note: When several indices are applied to the same coal, they often
do not predict the same results.
NA: Not applicable
CALCULATIONS OF COMMON ASH
SLAGGING, FOULING, EROSION AND ASH CORROSION INDICES
AND REDUCING ATM. ASH FUSION TEMPERATURES
OUTPUT SHEET:
PAGE 3
COAL ASH CORROSION INDICES:
Value I Rating
Hardgrove Grindability Index (HGI)
66
I
Low
FC/VM
2.86
Medium
Alkalies/Alkaline Earth Ratio
0.37
Medium
Alkalies/CaO Ratio
0.50
Low
Fe in Ash
7.00% Medium
Sulfur
1.00%
Low
Sulfur/Alkaline Earth Ratio
0.37
Medium
Acid/Base Ratio VS. Ash Content
1.4
2 4 6 8 10 12 14 16 182 24 26 28 30
1.2
"
1
32
34
0.8
Base/Acid Ratio
36
0.6
0.4
0.2
2 4 6 8 01214/161820222426
0
0
20
40
60
80
Ash Content (As Receive lbs/MMBTU
Furnace Cleaning Assessment
40
30
Ash Content (As Received) - lbs/MMBTU
20
10
0
1600.000
1800.000
2000.000
2200.000
2400.000
2600.000
2800.000
Ash Softening Temp,
H=W Reducing - F
CALCULATIONS OF COMMON ASH
SLAGGING, FOULING, EROSION AND ASH CORROSION INDICES
AND REDUCING ATM. ASH FUSION TEMPERATURES
Date:
16-Nov-95
INPUT SHEET:
PAGE 1
Coal Name:
Ekibastuz #5
As Received Coal
Ultimate Analysis
Ash Analysis
Carbon
47.00
SiO2
60.00
Hydrogen
4.00
A1203
30.00
Sulfur
1.00
Fe203
5.00
Nitrogen
1.00
CaO
2.00
Oxygen
4.00
MgO
0.70
Ash
37.00
Na20
0.30
Moisture
6.00
K20
0.70
TiO2
1.00
Sum
100.00
P2O5
0.00
SO3
0.30
As Received Coal
Sum
100.00
Proximate Analysis
Fixed Carbon
43
Volatiles
14
Ash
37
Moisture
6
Sum
100.00
Hardgrove Grindability Index (HGI)
66
HHV (Btu/lb)
7320
Red. Atmos. Initial Deformation Temp.- - F
2552
Red. Atmos. Softening Temp. - F
2732
Red. Atmos. Fluid Temp. - F
2822
* Note: Analysis does not total 100%
CALCULATIONS OF COMMON ASH
SLAGGING, FOULING, EROSION AND ASH CORROSION INDICES
AND REDUCING ATM. ASH FUSION TEMPERATURES
OUTPUT SHEET:
PAGE 2
Coal Name:
Ekibastuz #5
Ash Nature:
Bituminous
SLAGGING INDICES:
Value
Rating
Base/Acid Ratio
0.10
Low
Slagging Factor (Rs) (After Winegartner)
0.10
Low
Slagging Factor (Rs) (After Nolte & Horney)
0.04
Low
T250 Temperature - F
By Method of Nicholls and Reid
2901
Low
By Method of Watt and Fereday
2820
Low
Halfinger Furnace Cleanability
NA
Doubtful
Silica to Alumina Ratio
2.00
Low
Iron to Calcium Ratio
2.50
High
% Calcium in Ash
2.00
Low
Ash Content (As Received) - Lbs/MMBtu
50.55
Severe
Red. Atmos. Initial Deformation Temp. - F
2552
Low
Red. Atmos. Softening Temp. - F
2732
Low
Red. Atmos. Fluid Temp. - F
2822
Low
Delta (ID to F) Temp. - F
270
Medium
Calc. Red. Atmos. Initial Deformation Temp.- - F
2925
Low
Calc. Red. Atmos. Softening Temp. - F
2713
Low
Calc. Red. Atmos. Fluid Temp. - F
2790
Low
Calc. Delta (ID to F) Temp. - F
135
High
Furnace Design Parameter: Max. Allowable
Btu Input/Furn. Plan Area - Btu/Hr/Sq ft
1700000
NA
FOULING INDICES:
Value
Rating
Fouling Factor (Rf) (After Winegartner)
0.03
Low
Fouling Factor (Rf) (After Nolte & Homey)
0.05
NA
% Sodium in Ash
0.30
Low
Sodium Modifier
2.00
Higher
% Ash in Dry Coal (Ash Contains
0.30 % Na2O)
39.36
NA
Ash Sodium plus Potassium Content in
Dry Coal (in Equivalent % Na20)
0.30
Low
EROSION INDICES:
Value
Rating
Silica and Alumina in Ash - %
90.00
Severe
Ash Loading - Lbs/MMBTu
50.55
Severe
Max. Allowable Gas Velocity - Ft/Sec.
12.66
NA
Note: When several indices are applied to the same coal, they often
do not predict the same results.
NA: Not applicable
CALCULATIONS OF COMMON ASH
SLAGGING, FOULING, EROSION AND ASH CORROSION INDICES
AND REDUCING ATM. ASH FUSION TEMPERATURES
OUTPUT SHEET:
PAGE 3
COAL ASH CORROSION INDICES:
Value I Rating
Hardgrove Grindability Index (HGI)
66 I Low
FC/VM
3.07
Medium
Alkalies/Alkaline Earth Ratio
0.37
Medium
Alkalies/CaO Ratio
0.50
Low
Fe in Ash
5.00%
Medium
Sulfur
1.00%
Low
Sulfur/Alkaline Earth Ratio
0.37
Medium
81
Acid/Base Ratio vs. Ash Content
1.4
2 4 6 8 10 12 14 16 18 20 22 24 26 28 30
1.2
1
32
34
Base/Acid Ratio
0.8
36
0.6
0.4
0.2
2
4 6 8 10 12 14 16 18 20 22 24 26
0
0
20
40
60
Ash Content (As Received) - lbs/MMBTU
Furnace Cleaning Assessment
40
30
Ash Content (As Received) - lbs/MMBTU
20
Doubtful
Poor
10
Average
Good
0
1600.000
1800.000
2000.000
2200.000
2400.000
2600.000
2800.000
Ash Softening Temp, H=W Reducing - F
Burns and Roe Enterprises, Inc.
Technical Report
KAZAKSTAN EXPANDED ENERGY PROGRAM
HEAT AND POWER SYSTEM EFFICIENCY
IMPROVEMENTS
EKIBASTUZ PLANT
BLOCK NO. 3
FINAL REPORT
December 1995
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
no
TABLE OF CONTENTS
EKIBASTUZ EXPANDED ENERGY PROGRAM
TASK 2
HEAT AND POWER SYSTEM EFFICIENCY IMPROVEMENT
EKIBASTUZ POWER PLANT NO. 1
1.0
Introduction and Objective
2.0
Kazakstan Energy Sector Strategy
3.0
Block No. 3 Description and Evaluation
3.1
Steam Boiler
3.2
Steam Turbine/Generator
3.3
Auxiliary Plant Systems
3.4
Instrumentation and Controls
3.5
Air Pollution Controls
4.0
Block No. 3 Rehabilitation Recommendations
4.1
Steam Boiler
4.2
Steam Turbine/Generator
4.3
Auxiliary Plant Systems
4.4
Instrumentation and Controls
4.5
Air Pollution Controls
4.6
Rehabilitation Benefits
5.0
Capital Cost Estimates
6.0
Construction Schedule
5909-9 IB/EKI-TOC.DOC/1/16/96
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 NO, burner
VM
Volatile matter
FC
Fixed carbon
HGI
Hardgrove Grindability Index, HGI = (Kpo -0.32)/0.0149
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
5909-9 IB/EKI-TOC.DOC/1/16/96
ii
ofb
EKIBASTUZ BLOCK 3 REHABILITATION
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 by refurbishing of plant equipment, extending
service life and implementing a consumer energy saving program are the most cost
effective means for increasing energy independence. However, the necessary renovation
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
5909-98B/EKIBA.DOC/1/17/96
1
units at four different locations in Kazakstan. The Ekibastuz Electric Generation (Power)
Plant No. 1, Block No. 3 is one of the selected units 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 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 recommend appropriate modern
technology for increasing the availability and performance of the selected units.
These analyses also include 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. The effect of coal quality
improvement on increased plant performance is also included.
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.
5909-98B/EKIBA.DOC/1/16/96
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 environment, the power sector must upgrade its environmental control
5909-98B/EKIBA.DOC/1/16/96
3
89
equipment at heat and power generating stations. Installation of NO, 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.
5909-98B/EKIBA.DOC/1/16/96
4
90
3.0
BLOCK NO. 3 DESCRIPTION AND EVALUATION
3.1
STEAM BOILER
Equipment Descriptions
Block #3 consists of a 500 MWe supercritical main steam pressure turbine generator and a
monoblock once-through (OT) boiler, type P-57-3M, manufactured by the Podolsk
Machine Building Factory. The boiler is of the "T" configuration, with a balanced draft
dry bottom ash disposal furnace and opposed wall horizontal pulverized coal swirl type
burners. The boiler was designed to operate with medium volatile bituminous coal from
the Ekibastuz open cast mines. Natural gas is the auxiliary fuel for start-up and load
stabilization. A cross-sectional elevation of the boiler is shown in Fig. 3-1A & 1B. The
furnace is rectangular in shape, 9840 mm deep, 22000 mm wide and consists of fully water
cooled, vertical carbon steel tubewalls. The furnace, horizontal and vertical backpasses
roof tubes are steam cooled. The boiler is top supported, allowing for cubic thermal
expansion. The furnace is opposed wall horizontally fired, with a total of 24 (4 horizontal
rows of 6) swirl type pulverized coal burners with a heat input per burner of 45x10e6
kcal/h. Table 3-1 shows the design and current performance of the Boiler.
TABLE 3-1
Thermal Performance Design VS Current
Parameter
Units
Design
Current
Main steam flowrate
te/h
1650
1206
Main steam pressure
at.abs.
255
223
Main steam temperature
°C
545
518
Reheat steam flow
te/h
1364
Reheat steam pressure
at.abs.
40
Reheat steam temperature
°C
545
Feedwater temp. to economizer
°C
271
132
Comb. air temp. to main airheater
°C
50
30
Comb. air temp. leaving main airheater
°C
328
213
Fluegas temp. leaving main airheater
°C
145
155
Boiler Efficiency LHV basis
%
91.7
89.0
5909-98B/EKIBA.DOC/1/16/96
5
al
Figure 3-1A
BOILER LONGITUDINAL SECTION
62815
@+ +
+
56800
53500
+
::
0,0
12000
12000
12000
BOILER Pp-1650-255(P-57-3M)
PMC. 1. Котел Пп-1650-255 (П-57-3М).
LONGITUDINAL SECTION
Продольный pa3pe3
6
at
Figure 3-1B
BOILER CROSS-SECTION
57840
54350
17666
+
13580
0,0
12000
12000
BOILER Pp-1650-255(P-57-3M)
Pnc. 2. Котел CROSS-SECTION Пп-1850-255 (П-57-3М).
Поперечный pa3pe3
BEST AVAILABLE COPY
7
93
The superheater heating surfaces can be divided into three parts: radiant,
radiant/convective, and convective. The radiant primary superheater consists of furnace
and convective passes rooftubes. The second stage horizontal convective tubebanks are
positioned in the vertical rear passes and the finishing superheater pendant tubebanks are
situated in the short horizontal convective passes, near to the vertical upper furnace exit
plane. Main steam flow is divided into two parallel paths.
The two stage horizontal fully drainable convective reheater tubebanks are positioned in
the rear vertical passes. Superheated steam final temperature is controlled by firing rate
and trimmed by two stages of feedwater spray attemperators. The reheat steam final
temperature is controlled by bi-flux heat exchangers, (superheat to reheat steam) and by a
cold reheat steam bypass of the bi-flux heat exchangers. The two stage economizer
consists of fully drainable horizontal bare tubebanks positioned in the convective rear
passes, water in upflow and fluegas in downflow. The tubular type primary and secondary
airheaters are situated in an extension of the boiler house enclosure with fluegas in the
tubes in downflow and air over the tubes in crossflow. Cold end corrosion protection of
the airheaters is by separate hot air recirculation fans, one for Primary Air (PA), one for
Secondary Air (SA). Hot air is also recirculated into the forced draft fans suction from
cooling air provided for structural support beams of horizontal tubebanks in the rear
convective passes.
Based on the information and documentation received, Block #3 boiler does not have any
sootblowers installed. It is understood that furnace slagging is not an operating problem
and that the highly erosive mineral matter (ash) content of the Ekibastuz coal is non-
fouling, therefore we are not recommending the retrofit of heating surface cleaning
equipment. Furnace bottom ash is disposed as dry ash into refractory brick lined ash
hoppers supported on the basement floor. The draft plant consists of two forced draft
(FD) and two induced draft (ID) fans of radial flow centrifugal type, with electric motor
drives and radial inlet vane control.
The boiler is supplied with raw coal from eight silos each with a scraper type volumetric
feeder to eight type MMT-2600/2550/590 K high speed, horizontal shaft hammer mills
with integral centrifugal classifiers, electric motor drives, and a coal throughput per mill of
36 te/h at TCMR load. Each pulverizer supplies the pulverized coal to three swirl burners
through primary air/pulverized coal conduits (direct firing system). The pulverizers are
pressurized. Primary air flow for the flash drying and conveying of the pulverized coal is
provided by two primary air (PA) fans of radial flow centrifugal type. The fans are
positioned upstream of the tubular primary airheaters and are boosting FD fan pressure.
Particulate emission control equipment consists of four Venturi wet scrubbers in series
with two electrostatic precipitators (ESPs), all positioned upstream of the ID fans.
5909-98B/EKIBA.DOC/1/16/96
8
Condition Assessment of Boiler and Auxiliaries
Block #3 was commissioned on March 30, 1982, and has been in operation for
approximately 73,000 hours as of 1-1-1995, thus creep damage of the high
operating metal temperature thick-walled pressure parts is not yet anticipated.
However, there is some heating surfaces damage and high failure rates due to
low cycle fatigue. Additional operating problems with pressure parts are the
low quality of tube welds, high operating tube metal temperatures (tube
failures due to overheating) and serious flyash erosion wear. Block #3 total
number of starts was given as 482, with 74 cold starts out of this total.
Block #3 boiler main steam output is derated by approximately 27% [1206 vs
1650 te/h]. The derating is postulated to be due to a coal capacity throughput
shortfall of the existing high speed hammer mills. Another reason for the
derate is a capacity shortfall of the induced draft (ID) fans. The shortfall is due
to both an increased fluegas flowrate, caused by large amounts of unmeasured
ambient air ingress into the boiler setting, as well as an increased fluegas-side
draftloss through the tubular airheaters. The tubes are blocked up with
deposits caused by substantial cold-end acid dewpoint corrosion attack. While
the average fluegas exit temperature of the tubular airheaters, at full load, is
approximately 145°C, there is significant fluegas temperature stratification.
This is due to the design of the airheaters (Z configuration, two-flow/air in
crossflow over tubes). One side at the exit plane has a fluegas temperature as
low as 90°C, the other side a temperature as high as 200°C. The stratified low
fluegas temperature causes accelerated acid dew point type corrosion attack,
tube blockages by deposits, and corrosion products.
Pressure and temperature of the final main steam are derated [223 VS 255
at.abs., 518 vs 545°C]. The pressure derate is postulated to be due to boiler
feed pump problems. On a once-through type boiler the final main steam
pressure is maintained by the boiler feed pump (BFP). We are told that the
steam turbine drive of the BFP receives steam from the 4th stage extraction of
the main steam turbine. Below a certain part load of the main steam turbine,
the BFP drive turbine steam parameters are below design, thus resulting in low
feedwater pressures to the boiler. Another possibility for the lower main steam
pressure is a magnetite film build-up on the inside diameter of the furnace tube
circuits, with consequently increased flow resistance. This is unlikely however,
since the plant is using the combined [oxygen dosing] feedwater chemical
treatment. The final main steam temperature derate is postulated to be due to
the pulverizers coal throughput capacity shortfall. On an oT type boiler the
final main steam temperature is controlled by the [coal] firing rate.
Feedwater temperature to the economizer is substantially below design [132° C
VS 271°C]. At least 2 of the 3 HP feedwater heaters must have been out of
service when the performance data was recorded back in 1994. From the
design data it appears that the boiler was not designed to operate continuously
5909-98B/EKIBA.DOC/1/16/96
9
at full load with any of the HP heaters out-of-service. Even at the 27% derated
main steam flow, the total heat input into the furnace is higher than design,
with the substantially reduced feedwater inlet enthalpy to the economizer.
Plant personnel have confirmed that they are forced to operate for extended
time periods with one or two HP feedwater heaters out of service. These
heaters are a major maintenance item, due to design/constructional defects,
e.g., valves, flanges, tubing system, cover plates problems and they have very
low availability's. The plant urgently needs improved design/construction high
pressure feedwater heaters.
Heating surfaces cleaning equipment: As per documentation received, Unit #3
boiler does not have any sootblowers installed. It seems to us that apart from
high mineral matter content, the Ekibastuz coal has a low slagging & fouling
propensity thus the furnace heating surfaces slagging and convective heating
surfaces fouling is not a problem. Therefore, we have not allowed any cost for
retrofitting furnace tubewall and/or retractable sootblowers.
Pulverizer electric motors: The existing mill motors are rated at 1250 kWe
each and 6 kV. The motors may be reutilized for the retrofit of the vertical
spindle type medium speed pulverizers, since the specific power consumption
of this mill type is much less than that of the high speed hammer mills [approx.
9.5 VS 17 kWh/te]. However the motors will operate at part load with lower
efficiencies.
Raw coal bunkers: The plant requires installation of vibrators onto the
bunkers. This indicates coal bunker discharge flow problems. The solution
with vibrators is undesirable because their use will result in fatigue type bunker
wall failures. We suggest investigation into the possibility of modifying the
tapered bottom of the coal bunkers, e.g., steeper slopes, metal coating, larger
outlet opening, etc.
Raw coal feeders: These are given as scraper type, i.e., postulated to be
volumetric feeders. It is proposed to retrofit gravimetric coal feeders
simultaneously with the retrofit of the medium speed pulverizers. On an OT
type boiler, the monitoring of exact coal weight flow rates is important because
the ratios of coal flow/feedwater flow and coal flow/combustion air flow are
important control parameters.
NO₂ emissions control: In 1994 the maximum emission rate was 900 mg/nm3.
This would require an approximate 37% reduction to comply with the local
emission limit of 275 vppm or 565 mg/nm3. Such a reduction can be achieved
with in-furnace combustion modifications. The maximum in-furnace emission
reduction, using LNB's together with bulk furnace combustion air staging [use
of OFA], is approximately 55%.
The venturi scrubber fluegas exit temperature is ~50°C (winter) and 80°C
(summer). The moisture content of fluegas exiting the scrubbers is 50~70
5909-98B/EKIBA.DOC/1/16/96
10
ab
mg/nm3 and low temperature corrosion attack metal loss of ducting
downstream of scrubbers is about 1 mm/yr. Particulate collection efficiency of
the scrubbers is approximately 96%.
The electrostatic precipitators (ESP's) are inoperative due to serious damage
caused by acid dew point temperature corrosion and sulphuric acid
condensation.
The convective passes horizontal tubebanks (low steam temperature reheater,
economizer) and the vertical tubes of the tubular airheaters have substantial
flyash erosion damage, metal loss and tubewall thinning.
3.2
STEAM TURBINE/GENERATOR
General
Many problems with the steam turbines have been identified from discussions with plant
personnel and from review of documentation received. These problems have resulted in
an increase in Block heat rate, resulting in higher operating costs and an increase in
unscheduled outages resulting in lost generation due to equipment failure. Some of the
problems will result in the need for increased future inspections and deficiency corrections
of internal and external components of the turbine, which will require Block outage time
and result in increased maintenance expense.
The eight steam turbines at the Ekibastuz Power Plant No. 1 have a combined design
capacity of 4000 MW. However, the total working output of the plant at the time of the
Burns and Roe visit was only in the range of 670 to 750 MW. This plant was designed
with supercritical steam parameters, and as such, it should be operated as a base load plant
since it is supposed to have the best efficiency thermal cycle among coal fired stations.
However, the plant is plagued with frequent breakdowns and outages, requiring an
unusual number of starts for a traditional base load supercritical plant. The most
unreliable component of the plant was indicated by plant personnel to be the boilers. The
boilers typically are removed from service for repair on the average every 270 hours.
Most problems were noted by the plant personnel to be caused by the very abrasive coal
burned at Ekibastuz, with an average ash content of about 42-43%. Due to the frequent
shutdowns and the following startups, the turbine plant is also subjected to an increased
number of transients which causes deterioration and increased life consumption of the
equipment. A number of turbines have eroded last stage blades and are currently
operating with the two last stage blading rows removed. In addition, some of the units are
operating with their high pressure feedwater heaters bypassed. The maximum capability
of the various blocks and the total accumulated operating hours at the time of our visit are
shown in Table 3-2.
The actual number of operating hours of the various units and the actual number of unit
starts (including those which are a consequence of unplanned outage) are shown in Table
3-3 and Table 3-4, respectively.
5909-98B/EKIBA.DOC/1/16/96
11
TABLE 3-2
Maximum Generating Capability
of the
Ekibastuz Blocks
Block No.
1
2
3
4
5
6
7
8
Turbine Output
252
212
210
273
357
-
--
157
[MW]*
Number of Operating
83,181
73,868
72,872
70,538
63,423
67,640
65,570
67,785
Hours*
Date of Initial
4/80
12/80
4/81
5/82
12/82
4/83
12/83
12/84
Operation
*
As of March 1995
As of January 1, 1995
The operating data for the plant collected for the year 1994 indicates that the plant was
operating with a weighted average load of 306 MW per unit, and that the plant capacity
factor was a very low 19.4%. The total electrical energy generated, the average load,
steam parameters, capacity factors and other operating data for the various blocks are
shown in Table 3-5. The data shown in this table can give the reader an appreciation of
the degraded operating condition of this plant, especially when it is noted that the
projected capacity factor for the Ekibastuz Plant was 77%.
Because of the significantly degraded operating condition, the plant is embarking upon a
15 year rehabilitation program. The actual block rehabilitation plan will start with Block
#3 in 1997-1998 followed by Blocks 4, 1, 2, 5, 6, 7 and 8 to be completed by 2009.
Because the first unit to be rehabilitated is Block 3, this unit was selected by the plant
personnel for evaluation by Burns and Roe. The following paragraphs will concentrate on
the evaluation of the condition of the Block 3 turbine-generator and related plant
auxiliaries in order to develop recommendations for their rehabilitation.
Description and Performance Assessment
a)
Description of Turbine
Of the eight steam turbines operating at the Ekibastuz Plant three were manufactured by
the Kharhov Turbine Plant and five by the Leningrad Turbine Plant. They are however
basically the same Model K-500-240-2 turbines.
5909-98B/EKIBA.DOC/1/16/96
12
98
The Block 3 steam turbine was manufactured by the Kharkov Plant and it was installed in
April 1981. It is a nominal 500,000 kW, 3000 RPM, single reheat, tandem compound
condensing machine, designed to receive 1,570 t/h of supercritical main steam at a
pressure of 232 ata and temperature of 540°C at normal full load operation. There are
four separate turbine elements on a single shaft; one single flow high pressure (HP section,
one single flow intermediate pressure section, and two double flow low pressure (LP)
sections. A cross sectional drawing of the turbine is shown in Figure 3-2.
The number of stages in the turbine are: 10 in the HP section, 11 in the IP section, and 5
in each half of the two double flow LP sections. Interstage steam sealing strips are
provided to minimize bypass of steam around rotor blades and diaphragm nozzles.
Exhaust steam from the HP turbine is passed through the reheater in the boiler, and
returned to the IP section of the turbine. After exhausting from the IP section, the steam
flow splits, with half passing through each of the double flow LP sections.
Steam is extracted from the turbine and directed to five stages of low pressure feedwater
heating, three stages of high pressure feedwater heating, two feedwater pump turbines,
and a deaerator. The thermal cycle diagram for the steam turbine is shown in Figure 3-3.
Exhaust steam from the LP sections of the turbine is condensed at approximately 0.035
ata in a two pass shell-and-tube type surface condenser located under the LP turbine
sections.
Condensate from the condenser is heated through nine stages of feedwater heating, and
feedwater is delivered to the steam generator at a design temperature of 271 °C.
5909-98B/EKIBA.DOC/1/16/96
13
TABLE 3-3
Total Number of Operating Hours
of Various Turbine Generators
(From Initial Start to January 1, 1995)
Year
Block 1
Block 2
Block 3
Block 4
Block 5
Block 6
Block 7
Block 8
Total
1980
4,272
702
-
-
-
-
-
--
4,974
1981
4,806
5,785
4,248
82
-
-
--
-
14,921
1982
4,923
4,669
4,311
3,729
809
-
-
-
18,441
1983
5,456
4,324
4,903
6,191
7432
4,278
210
-
32,794
1984
6,014
3,711
7,352
6,460
3,105
5,930
5,820
1,096
39,488
1985
5,926
5,275
7,276
4,815
6,754
3,553
6,800
7,883
48,282
1986
6,535
6,724
4,952
6,381
7,244
7,806
7,485
6,862
53,989
1987
6,004
7,420
2,457
6,396
5,666
7,341
6,941
7,053
49,278
1988
4,632
4,411
6,200
7,405
5,997
7,649
7,613
6,997
50,904
1989
7,475
7,472
7,108
5,560
6,989
7,366
7,201
5,418
54,580
1990
6,770
6,907
5,087
7,149
5,314
2,517
6,880
7,422
48,046
1991
6,617
5,869
7,044
6,334
489
6,829
4,817
7,168
45,167
1992
4,777
4,286
5,741
4,218
5,574
7,160
5,471
5,287
42,514
1993
4,433
4,113
6,037
2,382
6,496
5,013
5,615
5,116
39,205
1994
4,541
2,200
156
3,436
1,554
2,198
717
7,483
22,285
Total
83,181
73,868
72,872
70,538
63,423
67,640
65,570
67,785
564,877
5909-98B/EKIBA.DOC/1/16/96
14
100
TABLE 3-4
Actual Number of Unit Starts
of Various Turbine Generators
(From Initial Start to January 1, 1995)
Year
Block 1
Block 2
Block 3
Block 4
Block 5
Block 6
Block 7
Block 8
Total
1980
60
18
-
-
-
-
-
-
78
1981
67
71
62
12
--
-
--
--
212
1982
51
50
38
49
25
-
-
-
213
1983
41
46
23
45
66
66
7
-
294
1984
62
45
36
49
17
31
50
20
310
1985
39
46
33
39
33
33
31
44
298
1986
44
46
51
43
34
26
34
43
321
1987
36
28
29
26
26
43
21
32
241
1988
26
26
35
38
33
24
33
29
244
1989
42
22
27
19
29
34
31
25
229
1990
32
32
13
39
18
15
34
30
213
1991
39
33
41
37
11
33
33
40
267
1992
41
40
48
42
49
38
41
49
348
1993
49
41
46
30
42
30
39
36
313
1994
51
58
3
52
24
21
4
25
238
Total
680
604
485
520
407
394
358
374
3,822
5909-98B/EKIBA.DOC/1/16/96
15
101
TABLE 3-5
1994 OPERATING DATA FOR THE EKIBASTUZ TURBINE GENERATORS
Indicators
Dim.
K-500-240-2 Turbine Generators
Gross Plant
1
2
3
4
5
6
7
8
Norm
Actual
Generated Electrical
thous
1,373,951
68,8572
63,533
107,6434
467,529
720,280
209,383
2,210,092
6809774
Power
kWh
Average Electric
MW
303
313
407
313
301
328
292
295
306
Load
Quantity of Hours in
hour
4541
2200
156
3436
1554
2198
717
7483
22285
Operation
Capacity Factor
%
31.4
15.7
1.5
24.6
10.7
16.4
4.8
50.5
19.4
No. of Starts
-
51
58
3
52
24
21
4
25
238
(including
unplanned)
Main Steam
kgf/
178
157
218
173
135
187
219
175
240
180
Pressure
sq.cm.
Condenser Pressure
kgf/
0.0596
0.0463
0.0516
0.0581
0.0715
0.0538
0.0626
0.0665
0.0374
0.0612
sq.cm.
Main Steam Temp.
°C
509
509
518
526
506
513
535
518
540
518
Hot Reheat Steam
°C
500
502
513
513
507
522
533
521
540
516
Temperature
Temperature of
°C
186
144
132
165
176
199
160
153
240
167
feedwater
Turbine Gross
kcal/
2,270
Heat Rate
kWh
5909-98B/EKIBA.DOC/1/16/96
16
Figure 3-2
TURBINE CROSS-SECTION
ПРОДОЛЬНЫЙ PA3PE3 ТУРБИНЫ K-500-240-2
$
:
SMS
neo
,
SIG7
1758-
3384
29500
BEST AVAILABLE COPY
17
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3-3
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11
TABLE 3-6
TECHNICAL CHARACTERISTICS OF THE STEAM TURBINE
Type
K-500-240-2
Nominal Output, MW
500
Main Steam Pressure, kg/cm2 (a)
240
Main Steam Temperature, °C
540
Hot Reheat Steam Temperature, °C
540
Hot Reheat Steam Pressure, kg/cm2 (a)
37.2
Main Steam Flow, t/h
1570
Number of Extractions
9
Extraction Configuration
3HPH+D+5LPH
Condenser Pressure, kg/cm2 (a)
0.0357
Number of Stages
41
Specific Heat Consumption, kcal/kWh
1841
Number of Turbine Bearings
8
Overall Length of Turbine, m
29.5
Turbine Manufacturer
Kharkov
Generator Model
TGV-500-2
Generator Rating kVA
588200
Power Factor
0.85
Starter Voltage, V
20000
Starter Current, A
17000
Frequency, Hz
50
Generator Cooling Medium
H₂
b)
Design and Current Performance of the Turbine
The technical characteristics of the K-500-240-2 steam turbine are shown in Table 3-6.
While the above table indicates that the steam turbine was designed with a cycle efficiency
of 46.7 percent, the current operating efficiency of the cycle is far less than the above
design figure. There are various reasons for the decreased cycle efficiency most of which
are due to the inability of the boiler to supply sufficient quantities of steam at the design
steam parameters. Other reasons are turbine and turbine cycle related.
As shown in Table 3-2 the current generating capability of Block 3 is only 210 MW. As
can be seen from Table 3-5 this unit could produce an average of 407 MW in 1994 making
it the block with the highest average output in that year. However, the block operated for
only 156 hours in 1994. This is because on January 15, 1994 the turbine hall roof caved in
and fell on top of the turbine, causing damage to it and its auxiliary equipment. This has
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caused a further reduction to the output capability of the block. Table 3-5 also indicates
that the main steam pressure and main steam and hot reheat steam temperatures were
much lower than design conditions. In addition the final feedwater temperature was less
than about half its design value. This is because the block had to operate with the high
pressure feedwater heater string out of service. This mode of operation increases the
power output obtainable from the block. Plant personnel indicated that bypassing the high
pressure heaters can add about 25 MW to the turbine output at full load. This output
increase is indicated in Table 3-7.
TABLE 3-7
EFFECT ON TURBINE OUTPUT OF OPERATING WITH
HIGH PRESSURE HEATERS BYPASSED
Turbine Output with
320
360
400
440
500
HP HTRS in Service,
MW
Turbine Output with
328.6
369.7
411.8
455
525
HP HTRS Bypassed,
MW
Output Increase, MW
8.6
9.7
11.8
15
25
Even though the operation without high pressure heaters in service increases the output
somewhat, it also increases turbine cycle heat rate. Since recent performance test data
was not available for Block 3, it was not possible to make a direct comparison of design
and test heat rates to accurately assess current turbine performance. However, turbine
performance curves (heat rate, steam flow, cycle heat input) for the load range between
300 and 500 MW prepared in 1990, were received from the power plant which were used
in estimating heat rate degradation. Based on a review of available design and operating
data it was concluded that performance degradation of Block No. 3 has occurred, and a
rough estimate of the extent of that degradation was calculated. This was done to
demonstrate that there is a need for refurbishment work on the turbine, in conjunction
with boiler refurbishment.
The turbine heat rate for the 1994 operating conditions of Block 3 was determined from
the best unit heat rate considering both the auxiliary load and steam generator efficiency.
This heat rate was determined for a turbine output of 407 MW. The actual 1995 turbine
heat rate however had to be determined at the new, even further reduced, unit output of
210 MW as given by the plant data for 1995. The determination of this heat rate utilized
the performance curve, the values on which had to be extrapolated below the 300 MW
range. Utilizing this curve a parallel curve was drawn through the actual operating point
determined for 1994. The final estimate of turbine heat rate then utilized the heat rate
read from the parallel curve at 210 MW, and finally it was adjusted to account for the
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effect on operating the block with the high pressure heaters bypassed. The various
outputs and turbine heat rates determined as well as the original performance (design)
figures are shown in Table 3-8.
From Table 3-8 it can be seen that compared to the original design conditions the current
actual operating heat rate of the turbine is about 37% higher. It can also be seen that the
full load heat rate of the turbine degraded by about 4% in 1990.
TABLE 3-8
DESIGN AND ESTIMATED TURBINE PERFORMANCE FIGURES
Time, Year
Design ('81)
1990
1/1994
3/1995
Turbine Output,
500
500
407
210
MW
Turbine Heat Rate,
1,841
1,915
2,081
2,529
kcal/kWh
This exercise does not quantify the heat rate deterioration with the unit operating under
full load condition, which may be significantly less than at 210 MW. It does, however,
provide an indication that turbine performance has deteriorated, and that turbine
refurbishment should be undertaken in conjunction with restoration of the boiler in a
program to restore the overall unit to "as new" efficiency and generating capacity.
Condition Assessment
a)
Block 3 Problems
Many problems with Block 3 turbine have been identified from discussion with plant
personnel, and from review of documentation received. Some of these problems tend to
result in an increase in block heat rate, which in turn results in higher operating costs.
Some of the problems tend to increase the probability of unscheduled outages and
resulting in lost generation due to equipment failure. Others of the problems tend to result
in the need for increased future inspections and deficiency corrections of internal and
external components of the turbine. Significant problems, which have been identified
relative to the turbine-generator are outlined in the following paragraphs.
Turbine Steam Path/Blading
The steam path components of the Block 3 turbine have significantly deteriorated. This is
obvious from the heat rate estimates discussed above. The design and actual internal
efficiencies of the intermediate pressure turbine cylinder for Blocks 2,3,4,6,7 and 8 are
shown in Table 3-9. The actual efficiency values in this table are based on tests performed
between 1990 and 1992. While no recent performance data exists it can be seen that of all
blocks, even before the roof collapse in 1994, the Block 3 turbine IP section efficiency
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was the worst at 83%. Because of the deterioration of the blocks operating with the
frequent startup regimen, the current internal efficiencies can be expected to be worse than
in 1990. The degradation is expected to be even more pronounced in the High Pressure
(HP) section of the turbine.
TABLE 3-9
INTERNAL EFFICIENCY OF INTERMEDIATE TURBINE SECTIONS
Block No.
2
3
4
5
6
7
Design Internal
91.2
91.2
91.2
91.2
91.2
91.2
Efficiency, %
Actual Internal Efficiency,
90.0
83.0
84.0
86.0
90.0
87.0
% (1990-1992)
Decrease in Efficiency,%
1.2
8.2
7.2
5.2
1.2
4.2
Plant maintenance data indicates that the No. 2 Low Pressure Cylinder of the Block 3
turbine experienced blade damage at the third stage in 1992 at which time the blades in
each flow section were removed.
Plant data also indicates that last stage blade problems have caused severe vibrations on
Blocks No. 4,5,6,7, and 8 turbines. These vibrations have caused failure of the blades and
consequent damage to other internal turbine parts. Although the turbine manufacturer has
proposed a new blading system utilizing titanium blades, sufficient funds to implement the
refurbishment have not been available. These turbines are currently operating with last
stage blades removed, a factor which contributes to degradation in turbine efficiency.
While the last stage blades on Block 3 have not been removed at this time, the same
problem is likely to occur at the No. 3 turbine as well, resulting in a long, costly forced
outage to repair the damage. The removal of the last stage blades was estimated to result
in an output loss of 25 MW.
In addition to the above, a decrease in efficiency also originates from the increased
interstate leakages within the turbine due to wear over the service life of the turbine..
Vibration/Alignment
It was reported by plant personnel that as a result of the collapse of the Turbine Building
roof, a significant amount of debris fell onto the No. 3 turbine/generator set and related
turbine plant auxiliary equipment. The unit now experiences recurring vibration problems,
probably due to increased misalignments of rotors and shells, and possible distortion of
major components, resulting from collapse of the roof. The vibrations in turn appear to
cause damage to the turbine and generator seals, resulting in oil leaks from the bearings
and hydrogen leaks from the generator. This condition can present a serious fire and
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explosion hazard. In fact, a fire due to the oil and hydrogen leaks did occur on the day of
the roof collapse.
Because the hydrogen leak is a serious problem, the plant personnel even considered to
cool the generator with nitrogen. Although a proposed change of generator cooling
medium from hydrogen to nitrogen would reduce the fire/explosion hazard, it would result
in a significant derate of the unit, and would not alleviate the vibration, alignment, and seal
leakage problems.
Bearings/Low Frequency Vibration
The plant personnel reported that the unit experiences low frequency vibrations when the
load is reduced below 450 MW. As the block now always operates at part loads, this
problem is continuous. The cause of low frequency vibration may be due to oil or steam
distribution problems. An investigation into these causes by the turbine manufacturer
indicated that while new modern self-adjusting bearings should be added to the HP and IP
turbine, the unit also has steam distribution problems at the nozzle block. Vibration
initiated the bearing problems and over heated bearings were among the most frequent
causes of turbine shutdowns.
Steam Admission and Regulating System
Unit outage records indicates a large number of turbine shutdowns were due to the turbine
regulation system failure itself, due to low pressure or clogged filters in the system, as well
as problems with regulation system pumps. The steam admission valves and their
actuating mechanisms were also the causes of turbine outages. This happened due to
damaged rack rollers for the regulating valve shaft and enlarged clearances in the control
valves.
Turbine Turning Gear
The turbine turning gear is in satisfactory condition. It currently has the capability to
rotate the turbine rotor at a constant speed of 4 RPM during the period when the block is
not in operation. However, there is no provision for "jogging" to rotate the rotor to
specific angular positions when required during maintenance. Such a feature should be
added as proposed by plant personnel to facilitate turbine maintenance work. The
maintenance people would like to use the jogging feature in future repair plans when
removing HP and IP rotor blades.
Flange Heating System
The turbine is equipped with a heating system for the flanges and stud bolts of the
horizontal joints between the upper and lower shells of the HP and IP turbines cylinders.
It was reported by plant personnel that this system could be modified to provide faster
turbine warm-up with lower thermal stresses during startup of the unit. A modernized
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flange heating system is desirable since the turbine is operated in a frequent startup
regimen.
In addition the block currently has no turbine stress monitoring system. Such a system is
recommended at this plant now because of the current operating regimen (frequent
startups and shutdowns).
Generator
The electric generator is not in a very good condition. As noted above the potential
explosion hazard due to hydrogen leaks through the seal system is one reason. The
generator rotor had problems which were corrected during the last overhaul. However,
the plant outage data indicates many outages due to generator related problems such as
water leaks (water leaking into generator relay shield, leak in stator), oil leaks at bearing
10 and increased temperature at bearings 11 and 12.
b)
Metal Control
The metal control laboratory personnel have been interviewed to assess the procedures
and equipment available at the plant to control metal conditions. In general the plant has
quite a large array of non-destructive examination (NDE) and destructive examination
(DE) equipment for the testing and inspection of the turbine, boiler, and main steam piping
components. These equipment include the following:
UD2-12
Ultrasonic defectoscope
PMD-70
Magnetic defectoscope
EDP-4
Eddy Current flaw detector
UT-93P
Ultrasonic thickness meter
MMP
Metallographic microscope
KM-30
Pendulum hammer
P-20
Tearing machine
TS-2m
Thickness meter
2109 TD
Thickness meter
MPB-2
Microscope
Micrometers
Sliding Calipers
Express-analysator for carbon
Photoelectrocolormeter
Microscope
Liquid penetrant testing, replication type creep testing equipment or boroscopes are not
currently available at the plant. Because the turbine has been in operation for only 73,000
hours, no creep damage of high temperature thick walled pressure parts was anticipated.
However, it should be noted that the current official design life of the K-500-240 turbines
is the lowest of all turbines, as follows:
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Component
Park Resources (hrs)
HP & IP Rotors
100,000
HP & IP Shells
100,000
Stop and Regulating Valves
100,000
Assuming the Block 3 turbine is to be operated with its average current operating hours
the remaining official design life of the above components will be exhausted within about 5
years. It was customary in the former USSR countries to grant official extension of lives
of various turbines, based on an assessment of the life consumption and the condition of a
turbine by a testing laboratory (such as Ekaterinburg, or others). Plant personnel indicated
that such a testing company was VTE (All Union Technical Institute), or Cybtech (which
can make remaining life assessment for the heating surfaces within steam generators), but
they expressed doubts about such companies coming to Ekibastuz without the prospects
of large financial rewards.
NDE testing and visual examination of turbine components are carried out periodically on
the HP and IP shells and valve bodies. The last time NDE was performed on Block 3 was
in 1990. During this examination the following defects were found:
HP Turbine Shell: 7 cracks found, with dimensions of up to 250 mm in length and
28 mm in depth.
IP Turbine Shell: 7 cracks found, with dimensions of up to 230 mm in length and
34 mm in depth.
Left Steam Chest: 2 cracks found, with dimensions of up to 150 mm in length and
25 mm in depth.
All of the above cracks have been repaired, as reported by plant personnel. However,
since cracks have been found, the discovery of additional cracks can be expected in the
future, and a plan for NDE should be in place for implementation during unit outages.
This is important for a plant with many blocks, but it is particularly so for Block 3 because
it was noted by the plant personnel that during the last maintenance outage in 1994,
following the January 15, 1994 incident, the shells of the turbine were not opened.
Therefore it is currently not known whether or how many additional internal cracks may
have developed during the last 5 years.
As it was noted above, currently there is no replication type creep testing capability
existing at this plant. However, as the plant is getting older and if further life extension is
to be granted for various components in the future, such testing capability would be highly
desirable to monitor potential creep damage of critical components. Utilization of such
testing equipment would enable the plant to better predict potential failures and to perform
predictive maintenance. The replication equipment is particularly suitable for a plant with
many boilers and turbines where it can be used more often.
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I'll
In addition, the following additional NDE equipment is recommended to be able to
efficiently handle the increased testing requirement of the many components at the
Ekibastuz plant.
Ultrasound defectoscopes:
UD-2-12
6 units
Producer - "Volna"
UD-2-17
2 units
Kishnev
UDS-2 "Pora" 2 units
"Uraltexenergo", Ekaterinburg
Ultrasound thickness meters
UT-93-P
10 units
"Volna", Kishinev
UT-81
5 units
"Introtest", Moscow
Metallographic microscopes with the device to measure the micro solidity (of the last
generation type "Neofot-21", GDR) 1 unit MIM, MMR Sankt-Petersburg
Quantitative structure analisators (type "Quantimet 360" and "Quantimet 720" of
"Cambridge Instruments" and "Epiquant" of "Karl Zeiss, Jena")
1 unit
Technology, devices and meters for ultrasound measurement of the residual deformation -
"Uraltexenergo", Ekaterinburg
Sets of reagents to carry out the colored defectoscoping and metallographic works (photo
films, reagents, developer, fixing solution)
Magnetic powder visualisator of defectors
VMP-40P
2 units "Infotex", Karaganda
Thickness meters:
TB-5042
4 units
"Tochpribor", Ivanovo
"UZIT-5"
2 units
Ekaterinburg
TK-2M
2 units
Ivanovo
In addition, a large number of ultrasound searchers will be necessary for control of pipes
of the steam generator boiling surfaces and for control of the welded joints of the steam
pipes.
c)
Spare Parts, Operation and Maintenance
Lack of spare parts was reported by plant personnel to be a problem. An adequate supply
of appropriate spare parts and trained maintenance staff 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 block
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to service as soon as possible. However, discussions with the Manager of Maintenance at
the plant indicated that the procurement of spare parts has become a tedious job. He also
noted that spare parts inventory using a computer should be introduced as soon as
possible. Currently there is no such system in use at the plant. On some metal control
efforts there is sometimes no follow-up because organizations such as VTE do not visit
the plant anymore. In this case they just mark the date when something occurred for the
record.
It was also noted that there is a major problem with the maintenance and operating staff.
This is because a large number of skilled personnel are leaving for various reasons (such as
moving to Russia). These people had special training and talent to operate and maintain
the equipment. However, with the skilled labor force leaving, the plant must hire less
skilled people from the street, which leads to a less efficient and less safe operation of the
plant equipment. The lack of stress monitoring in the turbine and a somewhat faster than
allowable heatup rate during startup of a block by less skilled personnel can result in an
accelerated life consumption of thick walled pressure parts.
The maintenance operations have slowed down due to the combination of the lack of
spare parts and the unavailability of funds and skilled personnel. For instance, a perfect
example for this is the 1994 capital repair of block 3. The overhaul which usually require
a duration of about 4-5 months was significantly extended for 7 months. Maintenance
operations started on this unit in August 1994 but were not finished till March 9, 1995.
Maintenance plans for several power plants in the Ekibastuz region called for the
establishment of a common repair facility which would house modern auxiliary equipment
which could handle and repair all power plant components. The facility was aimed at
serving the components of 5 plants:
Ekibastuz GRES-1
Ekibastuz GRES-2
Three other plants in the region
The establishment of this facility was conceived when it was realized that the cost of
transportation of components and spare parts between manufacturers and the power plants
exceeds the cost of maintenance. The construction of this facility, which is located within
about 3-4 miles of the GRES-1 plant has started, and there is a railroad running by it and
the Ekibastuz Plant. However, the building of the facility has never been completed due
to lack of money, equipment and personnel. Therefore, the maintenance of the Ekibastuz
Plant is performed at the old building at somewhat slower pace.
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Gil
3.3
AUXILIARY PLANT SYSTEMS
a)
Condenser
The condenser for Block 3 is a Type K-11520-2 single pressure surface condenser with
two water passes which is connected to the two exhaust connections of the steam turbine.
The technical characteristics of the condenser are shown in Table 3-10.
TABLE 3-10
TECHNICAL CHARACTERISTICS OF THE CONDENSER
Type
K-11520-2
Design Steam Flow (each half), t/h
430
Condenser Pressure, kg/cm2 (a)
0.0357
Circulating Water Flow (each half), t/h
25,740
Circulating Water Design Temperature, °C
12
Specific Steam Load, kg/m²h
37.6
Cooling Ratio
59.7
Condenser Surface Area (each half), m²
11,520
Condenser Active Tube Length, mm
8,890
Number of Tubes, each half
14,720
Tube diameter OD/ID, mm
28/24 and 28/26
Tube Material
MNM-5-1
Hydraulic Resistance, m W.C
4
The condition of the original tubes are generally satisfactory except for some plugged
tubes. The allowable plugging in the condenser is 10%. The plant reported occasional
problems with the tube-to-tube sheet joints. Circulating water can sometimes find its way
into the condenser steam space through tube joints. This will require the checking of
tubes for leakage and repair plugging, or replacement as necessary based on the results of
the leak check.
It was reported by plant personnel that considerable amounts of dirt accumulates in the
condenser tubes, especially during Spring and Summer. It appears that a condenser tube
cleaning system (such as the Tapprogge type) should be installed at this unit.
In addition, the condenser is experiencing excessive air in-leakages lately. This is because
of the more frequent shutdown and restarts of the unit. Sometimes plant personnel have a
limited amount of time to make repairs. The design allowable air in-leakage is 40 kg/h.
However, the actual air in-leakage into the vacuum system currently is 97 kg/h on Block
3. When there is no time to repair leaks the plant just starts up another air ejector. Air in-
leakages usually occur at the low pressure glands and at the horizontal flange of the LP
turbine cylinders.
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The components of the steam turbine bypass system connected to the condenser are
showing signs of deterioration due to the frequent startups associated with the frequent
outages. A thorough inspection of the turbine bypass valves should be performed, and
valves should be replaced if necessary.
b)
Feedwater Heaters
The unit utilizes a single string of 3 high pressure heaters and one string of low pressure
heaters. The HP heaters were manufactured by the Atom'machinery-building Utility,
Volgodonsk City plant and contain steam cooling, condensing and drain cooling zones,
and spiral coils. Because they are designed for very high pressures they have high wall
thickness. However, the plant reported that the Block 3 turbine is operating with the high
pressure heaters bypassed, which as mentioned before, contributes to the degradation of
turbine cycle efficiency. These heaters are a major maintenance item due to design and
constructional defects, i.e., valves, flanges, tubing systems, internal supports, cover plate
problems and have very low availabilities. These heaters require major rework or
replacements.
The low pressure heaters were reported to be in generally satisfactory condition.
c)
Deaerator Storage Tank
The plant has reported some cracks on the shell of the storage tank near the deaerator
section but not at the deaerator column weld attachment. This will require careful
examination and repair. It should be ensured that the unit has been repaired properly and
that no such crack develops in the future.
d)
Boiler Feed Pumps
There are many problems with the boiler feed pumps, especially since the roof collapsed
on the various auxiliary equipment on January 15, 1994. There are 2 full capacity boiler
feedpumps together with associated 2 booster pumps. The feedpumps are driven by their
own auxiliary turbines, with the turbines discharging into their own auxiliary condensers.
Besides the roof collapse problems, and natural wear and tear, the unreliability of the
feedpumps also compounded by improper maintenance. This is not because of the
maintenance plan followed by the plant but rather the inability of the maintenance people
to obtain the required spare parts. Therefore the plant has resorted to making the spare
parts themselves. However, these parts do not exactly correspond to the design of the
pumps and usually have no proper heat treatment. Both turbine driven feedpumps should
be replaced.
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e)
Boiler Feedpump Turbine Steam Extraction
Plant operating personnel reported that the Boiler Feedpump Turbine is receiving
insufficient steam supply from the fourth stage extraction of the Main Turbine due to low
extraction pressure.
Additional extraction piping connections from the No. III extraction connection on the
main turbine could provide driving steam with higher pressure and temperature for the
auxiliary turbines operating with the block at partial loads.
The current operating condition is unsatisfactory as the boilers produce steam at a
pressure much lower than the required main steam pressure of 240 kg/cm2 (a).
f)
Condensate Pumps, and Drain Pumps
There are two stages of condensate pumps. The first stage pumps, Model KCB-1600-90
transfer condensate from the condenser to the suction of the second stage pumps, or
condensate booster pumps, through the condensate polisher system. The booster pumps,
Model KC-1600-220Y4, transfer the condensate to the deaerator through the low
pressure feedwater heaters. These pumps are driven by 630 and 1250 kW motors,
respectively. These pumps have a history of problems with overheated bearings, broken
or leaking glands, as well as an overheated motor at booster pumps CP-IIB, and required
frequent repairs. These pumps were further damaged during the roof collapse in January
1994.
The drain pumps of the LP HTR #2 are similar in construction to the first stage
condensate pumps except they are sized for much smaller flow rate. Plant data indicates
these pumps have insufficient capacity under certain plan operating conditions and they
require replacement with higher capacity drain pumps.
3.4
PLANT INSTRUMENTATION AND CONTROLS
General
The instrumentation at the Ekibastuz 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 Ekibastuz Block 3
Instrumentation and Control System based on the information collected during the plant
visit and discussions with the plant management.
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(a) Load Control
Block 3 turbine uses a conventional mechanical governor with a 4% droop. The boiler
temperature controllers, when in automatic, control the fuel flow rate to the boiler. The
transport medium from mill to burner is primary air from the air heater. There is no
oxygen dilution for the transport air, but they have never had any explosions in the fuel
preparation and transport system. Steam pressure is varied using the feed pump speed
controllers.
Since the coal caloric content is so low and ash content so high, mazut is sometimes co-
fired with the coal in order to meet the boilers steam demand. There are no instruments
installed to determine mazut flow to the burners.
The combustion control of the boilers is actually a manual operation. The boiler control
system cannot "stay in automatic" within the present load range due to hardware and
tuning limitations. The operators control the boiler according to the established
procedures 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
reheater. 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. Fuel flow is controlled manually by observing steam temperature (and pressure) and
coal feeder motor current. The mills are rated at 40 tons per hour, and the feeders at 50
tons per hour each.
(b) Combustion 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 driven by the
oxygen analyzers assists the block operator in setting the correct combustion air flow rate.
Both forced draft fans discharge to a common header, then the secondary air is distributed
to the burners. The vanes are positioned by observing the fan discharge header pressure.
There is an automatic control system in place to balance the primary air fan vanes and the
forced draft fan vanes, but it is not used since the boilers cannot get to full load.
(c) Furnace Pressure Control
Each of the two 60% induced draft fans is controlled by an automatic control system. The
controlled variable is furnace pressure (vacuum). The low coal quality (high ash content)
requires that both fans be run even at low loads. The control loop uses electronic
controllers.
(d)
Steam Temperature Control
Steam flow is divided into parallel paths, with steam crossovers at the first and second
spray attemperator stages. There is an attemperation system in the parallel steam paths to
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the first and second stage desuperheaters using spray feedwater attemperation valves.
Each spray valve has its own dedicated controller. 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 stop valve
is the usual stopgap solution. Superheater outlet temperature and a derivative of
superheater inlet heat exchanger bypass temperature are compared to the setpoint to form
the control deviation. The final reheat steam temperature regulating valves also leak, so
they are not used at all.
(e) 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 final steam temperature, both
forced draft fans not in service, both induced draft fans not in service, no primary air fan in
service, low mazut pressure, and air heaters off.
(f)
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 burner will trip.
(g)
Stack Emissions Monitoring
There are no NO2, SO2, CO or CO₂ emission measurements on these blocks. There is an
opacity monitor installed, but it doesn't work due to heavy fluegas particulate loading.
Currently NO,, CO₂ and CO emissions 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 impossible for the plant maintenance staff to determine which boilers are operating
efficiently, and which may need repair or adjustment.
(h)
Turbine Control System
Since these are Kharkov turbines, the control fluid is water. The original mechanical
governors are still in operation. Each turbine uses 2 stop valves and 2 intercept valves
with integral governors.
(i) Turbine Interlock and Protection System
The following protection interlocks are installed: excessive movement at thrust bearing,
high steam temperature, low lubricating oil pressure, high water level in HP and LP
feedheaters, no boiler feed pump in service, generator electrical faults, loss of either rotor
5909-98B/EKIBA.DOC/1/16/96
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118
or stator cooling, and low hydrogen seal oil pressure and a loss of vacuum. All of the
above protection and interlocks are effected via electrical relays. Overspeed protection is
provided via overspeed rings and the hydraulic fluid system. 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.
(j)
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, axial movement, bearing oil outlet temperature and turbine speed by a
digital electronic system.
(k)
Feedwater Heating Controls
The condenser hotwell level and the levels in the feedwater heaters are controlled using
automatic regulators. All of the actuators are electrically operated. All heaters and the
condenser are equipped with water level gage glasses. Each extraction point is equipped
with a check valve to prevent water ingress. These valves are equipped with hydraulic
accelerators to improve the valve operating time.
(1)
Plant Alarm System
This is the original system which still operates in a satisfactory manner. A standard,
simple ISA sequence is used for display and control of the lamps and the horn. The plant
engineers are in the process of designing a solid state system to replace the relay based
system because sometimes it overloads and shuts down.
(m)
Thermal Insulation Detector
The boiler furnaces tubewall thermal insulation has deteriorated as has that of the air/flue
gas duct system. Visual examination has indicated that other plant systems also have
deteriorated insulation. A portable optical temperature detector would be a useful device
in locating and determining missing or deteriorating insulation.
3.5
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 Ekibastuz power plant dust collection equipment is
provided to remove a major portion of the fly ash from the flue gas before the flue gas is
discharged to the environment. The dust collection equipment operates with a collection
5909-98B/EKIBA.DOC/1/16/96
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119
efficiency of about 96%. No equipment is provided to control either NOx or SO₂
emissions.
In 1994, the plant's typical emission outputs were:
Emission
Amount, mg/nm³
Ash
2,480
NO,
900
SO₂
2,000
Kazakstani emission limits for new boilers are as follows:
Emission
Amount, mg/nm³
Ash
100
NOx
240
SO₂
400
Although the local requirement for maximum NO, emission is 565 mg/nm³, it is evident
that in order to meet the imposed emission limits, major modifications to the Air Pollution
Control equipment must be made.
The fly ash collection is achieved by the use of both wet venturi scrubbers and
electrostatic precipitators. The ESPS are located downstream of the scrubbers. This
arrangement has caused large scale corrosion of the ESP's. In 1987 a program was
started to upgrade the ash collection efficiency of all the units at the plant. In this program
the ESP's were removed and the venturi scrubbers were upgraded.
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120
4.0
BLOCK NO. 3 REHABILITATION RECOMMENDATIONS
4.1
STEAM BOILER
Based on the assessment of the current condition of the steam boiler for Block 3, the
following modifications are recommended:
Dismantling and removal of 24 (4 horizontal rows of 6) swirl type pulverized coal
burners.
Retrofit (supply and installation) of 24 (4 horizontal rows of 6) double register type
low NO, pc burners (LNB's) together with 12 (2 horizontal rows of 6) overfire air
(OFA) registers (optional) into prepared furnace tube openings. The heat input per
low NO, burner (LNB) is 45x10e6 kcal/h.
Dismantling and removal of 8 (type MMT-2600/2550/590K) high speed, horizontal
shaft hammer mills and integral centrifugal classifiers, electric motor drives, and steel
foundation rafts. The existing 8 raw coal conduits to the mills and 24 PA/PC conduits
to the burners (3 per mill) will be retained. The mill seal air fans and cold PA fans
complete with electric motor drives, and all 8 mill electric motor drives will also be
retained
Installation of medium speed, vertical shaft roller/tyre type mills complete with new
drive motors and dynamic classifiers. (seven mills to provide full load (TCMR) coal
throughput of approx. 41.2 te/h per mill and one spare mill). Maximum pulverizer
coal throughput capacity required is 50 te/h.
Refurbishing of boiler furnace tubewalls setting (refractory, insulation, casing)
including the vertical furnace walls, tube hopper walls, sidewalls of horizontal
convective pass, furnace and convective horizontal pass roof.
Refurbishing of vertical convective passes walls refractory brick setting and casing as
needed.
Refurbishing of boiler outlet to tubular airheaters, tubular airheaters to Venturi wet
scrubbers, scrubbers to ESP's, ESP's to ID fans suction side fluegas ducts, expansion
joints, dampers and hanger supports as required. Alternatively dismantling and
removal of the existing fluegas system and reconstruction with reinforced concrete
ducting could also be performed. However, our cost estimate is based on refurbishing
of the existing ducting system.
Refurbishing of furnace and horizontal backpasses rooftubes superheater tube
penetration seals as required.
5909-98B/EKIBA.DOC/1/16/96
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121
Refurbishing of horizontal drainable superheater, reheater, economizer tubebanks in
the brick-set vertical convective passes tube penetration seals as required.
Refurbishing of 2 Primary air and 2 Secondary air tubular airheaters (fluegas in tubes
in downflow, air over tubes in crossflow) as required.
Replacement of 2 axial flow, induced draft (ID) fan impellers and control vanes. As an
alternative, dismantle/remove the existing 2 ID fans and install 4 new ID fans, together
with modified fluegas ducting to/from the new fans. Our cost estimate is based on
replacement of existing fans with new fans.
We have included in our cost estimate an allowance for repairing and refurbishing the
existing forced draft fans.
Main purpose of the above listed refurbishment cost items is to restore boiler design
output, increase availability, and improve operational reliability. Some of the items will
also provide boiler efficiency improvement.
Time period scheduled by the power plant for the refurbishment activities of Block #3 is
1997-98.
4.2
STEAM TURBINE/GENERATOR
Based on the assessment of the current performance and condition of the Block 3 steam
turbine, the following major replacements and modifications are recommended:
a)
Steam Turbine
Block 3 turbine has experienced various problems, including a roof collapse on January
15, 1994. The turbine has problems with its steam distribution and control systems and
has vibration problems. The block has been operated with drastically reduced load with
the HP Heaters bypassed and with an increased turbine cycle heat rate. Its steam path has
suffered efficiency degradation due to wear. In an effort to restore the block's capacity
and operating efficiency, and to extend its life beyond its original design life, the following
modifications and replacements are recommended.
Replace main steam stop valves, regulating valves, and steam chest.
Replace the HP cylinder and rotor.
Replace reheat stop and intercept valves.
Open the shell of the IP section and perform NDE and visual inspection to detect
cracks or faults at rotor, lower and upper shell surfaces, and obtain approval for
extended life from an approved laboratory and the turbine manufacturer. Repair any
blade damage as required. Recondition internal seals to as new condition.
Replace existing bearings with self adjusting modern types at the IP section. (Similar
modern bearings are assumed to be furnished with the new HP section).
5909-98B/EKIBA.DOC/1/16/96
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Replace front standard and install new turbine control and supervisory system
including (TSE) turbine stress monitoring system to be used for controlled startups
and load changes.
Modernize turbine flange and stud-bolt heating system of the HP and IP turbines to be
able to provide more efficient startups.
Check the existing conditions of the last stage blades and bands in the two LP
sections. Replace blading as necessary. If last stages require replacement, replace
them with titanium blades.
Equip the turbine turning gear with jogging feature to enable it to be used during
maintenance when removing and installing turbine blades.
Refurbish turbine bypass system as required including turbine bypass valves.
b)
Generator
Replace the electric generator including the hydrogen seal and cooling systems.
c)
NDE Equipment
Since there is no replication type creep monitoring equipment or boroscopes presently
available at this plant, and in order to make the inspection and testing of the many
components of the eight steam turbines (and associated steam boilers and steam piping)
more efficient, it is recommended that these and the additional equipment described under
paragraph 3.2) be purchased. Availability of such equipment becomes more desirable as
the plant major equipment ages.
d)
Spare Parts
It is recommended that, an adequate inventory of spare parts for the upgraded (and
existing) equipment be established. This has also been recommended by cognizant plant
engineering management, and the manufacturers of major plant equipment. In addition, a
computerized spare parts inventory system should be implemented in the future when
more money becomes available.
The purpose of the above changes and refurbishments is to restore the output capability of
the turbine with increased reliability and availability, and to extend the turbine/generator
operating life. Some of the refurbishment items will also provide turbine heat rate
improvement.
4.3
AUXILIARY PLANT SYSTEMS
Based on the assessment of the current condition of the turbine plant auxiliary equipment
the following additional modifications and replacements are recommended:
5909-98B/EKIBA.DOC/1/16/96
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123
a)
Condenser
Replace previously plugged tubes and replace existing leaking tubes. It is estimated
that approximately 25% of the condenser tubes will need replacement.
Correct existing air inleakages and institute a more formal air inleakage detection
program to systematically detect and eliminate air ingress into the vacuum space of the
condenser.
Retrofit circulating water side of condenser with sponge ball (Taprogge type) tube
cleaning system.
b)
Feedwater and Condensate System
Replace the string of high pressure feedwater heaters with new ones.
Replace the existing feedwater and booster pumps.
Provide alternate steam supply piping from the No. 3 extraction of the main turbine to
the auxiliary feedpump turbines to provide driving steam of adequate parameters to be
utilized during part load operation. Also, inspect and refurbish blades and seals of the
feedpump turbines, and recondition them as necessary.
Inspect the deaerator to confirm its structural soundness and proper functioning.
Replace the first and second stage condensate (and booster) pumps damaged during
the January 1994 roof collapse.
Replace the drain pumps of the LP HTR #2 with larger capacity drain pumps.
The time period scheduled for these and the turbine/generator rehabilitation items for
Block 3 is during the years 1997-1998.
4.4 INSTRUMENTATION AND CONTROL
The following plant instrumentation and control improvements are recommended, based
on an assessment of Block 3, and discussions with cognizant plant engineering
management.
1.
Four high temperature O₂ analyzers, (in-situ type, positioned near the furnace exit
planes) to achieve optimum combustion efficiency.
2.
Good quality portable combustion analyzer (CO, SO2, NO, combustibles)
5909-98B/EKIBA.DOC/1/17/96
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124
3.
Replace portions of the boiler control system with modern single loop controllers
to achieve automatic control of the steam pressure and temperature throughout the
load range.
4.
NOx emissions monitoring equipment for the boiler to determine the effectiveness
of NO, reduction initiatives.
5.
Particulate emissions monitoring for boiler flue gas to determine the effectiveness
of the scrubbers and electrofilters.
6.
SO₂ emissions monitoring equipment for the boiler.
7.
A heat spy for measuring heat leakages and electrical hot spots.
8.
Non-contact type flow meters to measure mazut consumption by the boiler.
9.
Refurbish the existing superheat and reheater attemperator control valves.
10.
New turbine control and supervisory system including turbine stress monitor.
11.
Moisture monitoring equipment to determine the quantity of moisture in the boiler
flue gas in order to perform combustion calculations.
The above list was developed during the condition assessment of Block 3 and is
considered necessary for rehabilitation and modernization. Implementation of these
recommendations will extend the plant life and yield an improvement in reliability and
availability and reduce maintenance costs.
4.5
AIR POLLUTION CONTROLS
Rehabilitation of the steam boilers and turbine systems will be accompanied by
improvements in the air pollution control systems with the objective of reducing emissions.
Present levels of emissions have been estimated at:
NOx
900 mg/Nm³
SO₂
2,000 mg/Nm³
Ash
2,480 mg/Nm³
with 96% efficient dust collection
Pollution control equipment options for reduction in these emissions are described below:
5909-98B/EKIBA.DOC/1/16/96
39
NO, emissions can be reduced to 400-450 mg/Nm³ by modification to the combustion
system. Application of low NO, burners (LNB) together with combustion air staging
(OFA) would be required to achieve this emission level.
Reducing NO, emissions to 240 mg/Nm³ (the limit suggested for new boilers) requires
post combustion NO, controls. A 50% reduction in NOx emissions (from 450
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.
Reduction in SO₂ emissions would require post combustion controls. Reducing
emissions from the uncontrolled level of 2000 mg/Nm³ to the suggested level of 400
mg/Nm³, an 80% reduction, requires the application of flue gas desulfurization
technology. Lime based semi-dry scrubbing is the most likely technology to achieve
this emission reduction.
Reduction in particulate (ash) emissions to achieve the suggested limit of 100 mg/Nm3
would require dust collection equipment with'a collection efficiency of 99.84%. This
collection can be achieved utilizing a high efficiency electrostatic precipitation or a
fabric filter system. Wet (venturi) scrubbing technology, is not capable of achieving
such a collection efficiency.
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. The SOx and NO, control equipment recommendations will be
made at the conclusion of the above referred Environmental Improvement Study.
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126
4.6
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,
1,206
1,650
36.8
t/h
Boiler Efficiency, %
89
91.7
2.7
Turbine/Generator
210
500
138%
Output, MWe
Heat Rate, kcal/kWh
2,529
1,841
27.2
Plant Life Extension
-
15 years
Increase in Plant
-
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 block
by increasing its availability and reliability, decreasing Operating and Maintenance costs,
and extending the life of the block. 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 NO, discharge from the block and should
allow the block to meet future environmental pollution limits. In addition, the replacement
of 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 plant
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 when Block 3
plant were to be shutdown due to unplanned (forced) outages.
One additional benefit of Block 3 rehabilitation is an increase in plant availability and
reliability due to major renovation and upgrade of critical plant components such as
5909-98B/EKIBA.DOC/1/16/96
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127
boilers, turbines, auxiliary plant equipment and instrumentation and controls upgrades. It
is estimated that the Block 3 availability and reliability will improve by 10 to 12 percent as
a result of the proposed Block 3 rehabilitation.
5909-98B/EKIBA.DOC/1/16/96
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128
5.0
CAPITAL COST ESTIMATES
Cost estimates for the various rehabilitation items have been developed based on Burns
and Roe in-house 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
Replacement of existing 8 Hammer Mills with 8 new Vertical Spindle Roller/or Tyre
type Mills
Installation of new Dynamic (rotating)Classifiers
Replacement of Boiler Setting (refractory, insulation & casing)
Repair (4) Tubular Air Heaters
Installation of new low NO, Burners and overfire air nozzles
Replacement of two (2) Induced Draft Fans
Repair or replace tube penetration seals
Repair flue gas duct system
Replace HP Cylinder and Rotor.
Replace Stop Valves, Regulating Valves, and Steam Chest.
Replace RH Stop and Intercept Valves.
Replace bearing with self-adjusting modern type for the HP and IP sections.
Purchase additional NDE Equipment.
Perform NDE Testing of the IP Turbine section (cracks, creep) - repair as necessary.
Install Turbine Control and Supervisory System including Turbine Stress Monitoring.
Modernize Turbine Flange and Studbolt Heating System for HP and IP turbines.
Replace the valves in the Turbine Bypass (steam dump) System.
Check the present condition of the last stage blades and bands in the LP Cylinders.
Replace if necessary (cost of 4 sets of blade included).
Replace Electric Generator and seal and cooling system.
Equip the Turbine Turning Gear with Jogging Feature (cost of new turning gear
included).
Replace damaged or leaking tubes in the condenser (25% of tubing replaced).
Replace HP Feedwater Heaters.
Replace Feedwater Pumps.
Provide Alternate Steam Supply Connection from the No. 3 Turbine Extraction to the
Feedpump Turbines.
Inspect Deaerator for structural soundness and proper functioning.
Replace condensate pumps and booster pumps (2 condensate pumps and 2 booster
pumps).
Replace 2 Drain pumps for LP HTR #2.
Remove existing wet scrubbers and precipitators
Install two (2) new Electrostatic Precipitators
Install Emissions and Air Flow Monitoring Equipment
Install Boiler Emission Monitoring Equipment
5909-98B/EKIBA.DOC/1/16/96
43
Miscellaneous Instrumentation and Controls System Upgrades
The project cost estimate is conceptual in nature, and was based on information obtained
during Burns and Roe's recent site visit.
Direct Costs
Pricing for major equipment and materials were developed from Burns and Roe's
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 to 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 of the components at the conceptual stage of design.
Contingency was applied to the direct labor and material costs.
Other Costs
Additional costs such as Engineers, 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.
5909-98B/EKIBA.DOC/1/16/96
44
PRELIMINARY COST ESTIMATE
REHABILITATION OF 500 MW BLOCK No. 3
EKIBASTUZ COAL FIRED POWER PLANT KAZAKSTAN
ITEM
LABOR
WESTERN
LOCAL
TOTAL
COST $
MAT'L $
MAT'L COSTS
COST
BOILERS
Remove Existing Burners (24 Total)
387,200
11,600
398,800
Install New Low NOx Burners & OFA System
1,224,300
14,618,000
396,100
16,238,400
Remove Existing Hammer Mills & Classifiers
198,400
6,000
204,400
Remove Existing Hammer Mill Foundations
143,400
4,300
147,700
Repair PA/PC Ductwork & Fans
225,600
753,200
29,400
1,008,200
Install New Roller Mill Foundations (8)
148,800
31,300
180,100
Install New Roller Mills (8)
517,400
5,623,000
184,200
6,324,600
Install New Classifiers
423,000
2,780,000
96,100
3,299,100
Boiler Refractory, Insulation & Casing Repair
796,800
4,255,000
151,600
5,203,400
Tube Penetrations & Seals
206,400
985,000
35,700
1,227,100
Repair Forced Draft Fans
147,800
621,900
54,300
824,000
Remove Old Induced Draft Fans
150,400
4,500
154,900
Replace Induced Draft Fans
293,100
3,428,000
111,600
3,832,700
Repair Flue Gas Ductwork
695,400
5,821,000
195,500
6,711,900
Perform Non-Destructive Testing (Allowance)
50,000
50,000
Perform a Draft Plant Assessment on a Boiler Train (Allowance)
60,000
60,000
TOTAL BOILER WORK
4,056,500
24,267,100
904,500
29,228,100
TURBINE GENERATOR
Replace HP Cyliner & Rotor
500,000
7,300,000
234,000
8,034,000
Replace Stop Valves and Steam Chest
134,000
1,250,000
41,500
1,425,500
Replace RH Stop and Intercept Valves
122,700
900,000
30,700
1,053,400
Replace Bearings
12,300
50,000
1,900
64,200
Perform NDE Testing on IP and LP Sections
0
45,000
13,500
58,500
Supply NDE Testing Equipment
0
25,000
0
25,000
New Turbine Control System
134,400
1,000,000
34,000
1,168,400
Replace Front Standard & Heating Flange
135,200
1,268,000
42,100
1,445,300
Replace Turbine By-Pass System
38,200
425,000
13,900
477,100
Replace 4 Rows Last Stage Blading w/Titanium Blades
58,900
500,000
16,800
575,700
Install Turning Gear
6,000
25,000
900
31,900
TOTAL TURBINE WORK
1,141,700
12,788,000
429,300
14,359,000
01
SHEET 1 OF 3
PRELIMINARY COST ESTIMATE
REHABILITATION OF 500 MW BLOCK No. 3
EKIBASTUZ COAL FIRED POWER PLANT KAZAKSTAN
ITEM
LABOR
WESTERN
LOCAL
TOTAL
COST $
MAT'L $
MAT'L COSTS
COST
AUXILLIARY PLANT SYSTEMS
Replace 25% of Condenser Tubes
181,900
875,000
19,700
1,076,600
Install Condenser Cleaning System
168,000
1,455,000
13,500
1,636,500
Replace HP Feedwater Heaters
209,800
1,800,000
36,300
2,046,100
Replace LP Heater Drain Pumps
8,500
64,000
1,400
73,900
Replace Feedwater Pumps
140,800
1,500,000
49,200
1,690,000
Provide Alternate Steam Extraction to BFP
38,500
150,000
2,700
191,200
Inspect Deaerator (Allowance)
0
20,000
600
20,600
Replace Condensate Pump Bearings & Glands
25,600
100,000
3,800
129,400
TOTAL AUXILLIARY SYSTEMS WORK
773,100
5,964,000
127,200
6,864,300
INSTRUMENTATION & CONTROLS
Install Emissions Monitoring Equipment
172,000
565,000
14,700
751,700
Install Boiler Monitoring Equipment
74,700
255,900
6,600
337,200
Install Turbine Monitoring Equipment
57,900
145,300
4,100
207,300
Miscellaneous Instrumentation & Controls
101,300
817,500
18,400
937,200
TOTAL INSTRUMENTS & CONTROLS
405,900
1,783,700
43,800
2,233,400
ELECTRICAL SYSTEM
Repair Plant Wiring & Cable
85,600
1,000,000
21,700
1,107,300
Replace Generator
230,100
14,000,000
284,600
14,514,700
TOTAL ELECTRICAL WORK
315,700
15,000,000
306,300
15,622,000
ENVIRONMENTAL SYSTEM
Remove Existing Precipitator
194,900
3,900
198,800
Install New Electrostatic Precipitator
467,200
11,400,000
237,300
12,104,500
TOTAL ENVIRONMENTAL WORK
662,100
11,400,000
241,200
12,303,300
SUBTOTAL
7,355,000
71,202,800
2,052,300
80,610,100
Freight
5,054,300
Contingency (10%)
7,263,200
TOTAL COST OF REHABILITATION
92,927,600
$/KW
186
01 6
SHEET 2 OF 3
ALL COSTS ARE SHOWN IN 1995 DOLLARS
IF THIS PROJECT WERE TO BE CONSTRUCTED IN THE USA
THE FOLLOWING ADDITIONAL COSTS WOULD APPLY:
DIRECT COSTS FROM PREVIOUS PAGE
92,927,600
Engineering Costs
4,836,606
Construction Management Costs
2,418,303
Start-Up Costs
1,612,202
Construction Equipment Costs
1,750,000
Interest During Construction
7,434,208
Escalation
8,878,314
TOTAL COST INCLUDING THE ITEMS ABOVE
$/KW240
119,857,233
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
01/12/96
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.
5909-98B/EKIBA.DOC/1/16/96
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134
CONSTRUCTION SCHEDULE FOR THE REHABILITATION OF THE EKIBASTUZ PLANT BLOCK NO. 3
Tasks
Month 1
Month 2
Month 3
Month 4
Month 5
Month 6
Month 7
Month 8
BOILER WORK
Remove Boiler Mechanical Components (Burners, Tubes, etc.)
Remove Boiler Auxiliary Equip. (Mills, Fans, etc.)
Remove Mill Foundations
Install New Mech. Components Including Heat Transfer Surfaces
Install New Mills and Auxiliaries Including Fans
Repair Boiler Casing, Refractories, Insulation, etc.
TURBINE GENERATOR
Purchase NDE Equipment and Test Selected Components
Replace Various Turbine Components Including Piping and Valves
Replace Electric Generator and Cooling System
Install New Turbine Control System (Stress Monitoring)
AUXILIARY PLANT SYSTEM
Replace Feedwater and Condensate Pumps
Replace Feedwater Heaters
Replace Plugged Condenser Tubing and Install Tube Cleaning System
Replace Condensate and Drain Pumps
Install Extraction Steam Piping From No. 3 Turbine Extraction
ENVIRONMENTAL
Remove Venturi Scrubbers and Replace Electric Precipitators
INSTRUMENTATION
Install Emissions and Air Flow Monitoring Equipment
Install Boiler and Turbine Monitoring Equipment
Misc. Instrumentation & Controls System Upgrades
STARTUP AND CHECKOUT
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CONSTRUCTION SCHEDULE FOR THE REHABILITATION OF THE EKIBASTUZ PLANT BLOCK NO. 3
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
$
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