MON TS Ulaanbaatar Power Plant

Draft Final Report

PROMOTION OF RENEWABLE ENERGY, ENERGY EFFICIENCY AND GREENHOUSE GAS ABATEMENT (PREGA)

Mongolia

ENERGY EFFICIENCY STUDY OF THERMAL POWER PLANT #4

ULAANBAATAR, MONGOLIA

A Technical Study Report1

February 2006

1 Prepared by the National Technical Experts: Mendbayar Badarch, Mongolian Nature and Environment Consortium (Environment Specialist), Damdinsuren Gantulga, IT Power Mongolia (Energy Specialist), Gombusoren Luvsan, MCS International Inc (Financial Analyst), and Jargal Dorjpurev, EEC Co. Ltd (Technical Specialist)

2

Table of Contents

List of Tables 3 List of Figures 3

1.0 Background 4 1.1 Introduction 4

1.2 Energy Sector of Mongolia 5

1.3 Current Status of Power Plant TES#4 14

1.4 Upgrades/Renovations 31

1.5 Environmental Protection 34

2.0 Energy Efficiency Improvement Options 39

3.0 Conclusions 45

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List of Tables

Table 1.1.1 Avoided CO2 Emissions from the Energy Efficiency Options (TES#4) 5 Table 1.2.1 Mongolia: Energy Balances 7 Table 1.2.2 Existing Combined Heat and Power Plants in CES 8 Table 1.2.3 Boilers of the Existing CHPs in Mongolia 9 Table 1.2.4 Turbine Sets in Existing CHPs in Mongolia 10 Table 1.2.5 Power Plants of CES: Internal Use of Electricity, % 10 Table 1.2.6 CES: Electrical Efficiencies of the Power Plants 11 Table 1.2.7 Main Energy Indices of CES Operation GWH 11 Table 1.2.8 Specific Fuel Consumption and Calorific Values 13 Table 1.3.1 Present Status of Generators -Ulaanbaatar TES#4 16 Table 1.3.2 Present Status of Steam Turbines 17 Table 1.3.3 Specifications of the Steam Turbines 17 Table 1.3.4 Rehabilitated and Rehabilitating Boilers 18 Table 1.3.5 Specifications of the Boiler 19 Table 1.3.6 Characteristics of the Boilers 22 Table 1.3.7 Present Status of the Components of Boilers 23 Table 1.3.8. Characteristics and Present Status of the Auxiliary Equipment 23 Table 1.3.9 Present Status of Electrical Equipment 25 Table 1.5.1 Temperature, Precipitation and Humidity in Ulaanbaatar City 34 Table 1.5.2 Method of Analysis 35 Table 1.5.3 Dust Data (Annual) 36 Table 1.5.4 SO2, NO2 and O2 Data 36 Table 1.5.5 Sound Level Measurement (Inside of Power Station) 38 Table 1.5.6 Sound Level Measurement (Outside of Power Station) 38 Table 1.5.7 Noise Standard 38 Table 1.5.8 Present Status of Environmental Equipment 39 Table 2.1 Measures that may improve the Efficiency of Coal-Fired Power Plants 40 Table 2.1B Avoided CO2 Emissions from Energy Efficiency Options 41 Table 2.2 Selected Clean Coal Technologies 41

List of Figures Figure 1.2.1 Development of GDP per Person and Electricity use per GDP 6 Figure 1.2.2 Typical Load Curves of CES Grid 12 Figure 1.3.1 General Layout of the TES#4 15 Figure 1.3.2 Coal Feed and Boiler 21 Figure 1.3.3 Direct Firing Mill System 22 Figure 1.3.4 Cool Handling System 30 Figure 1.5.1 Ash Disposal Flow Diagram with Water 37 Figure 1.5.2 Measuring Sound Level at Power Station 37 Figure 1.5.3 Sound Level Measurement Points (Outside of Power Station) 38

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1 Background 1.1 Introduction

Today, global warming has become the subject of considerable public debate and

the concern over the potential effect of CO2 emissions from fossil fuel power plants’ contribution to global warming, which is now a key issue for the future of power generation worldwide. Coal plays a key role in ensuring a sustainable future for Mongolia as this energy source is used for electricity and heat generation and the related CO2 accounts for around 90,0 % of total carbon emissions from Mongolia, therefore any strategy to reduce Mongolia’s CO2 emission levels must address the efficiency of coal based electricity and heat generation in the main cities and the province (aimag) centers.

This paper addresses the assessment of energy efficiency options in the coal-fired power plant Thermal and Electric Station #4 (TES#4) in the context of sustainable development and greenhouse gas (GHG) mitigation strategies for Mongolian coal-fired power plants. The report is based on the characteristics of Mongolia’s largest coal-fired combined heat and power generation plant, TES #4. Although not specifically addressed, the importance of demand-side management, including energy conservation programs, as a common sense, cost-effective source reduction option cannot be overstated. Further, the current potential and future importance of renewable energy including solar-derived power should also not be underestimated.

There is a wide range of electricity-generating technologies available that could significantly reduce GHG emissions worldwide. As stated in the Mongolian Energy Master Plan of 2001, the new heat and power generation capacities should be of new energy generation technologies, and should also include clean coal development technologies. Coal-fired power plants may vary greatly in their generating capacities and the types of boiler technology that they employ. As coal is the unique energy resource in Mongolia, we suggest to conduct a study which should demonstrate the commercial viability of new energy technologies with low greenhouse gas emissions in the near term future. Also it should focus on efficiency improvements and clean coal development technologies.

Attention in this paper is focused on the coal-fired combined power and heat generation plants as they represent the largest use of coal in Mongolia. For Mongolia, more consideration has to be given to potential improvements in conventional coal-fired boiler steam turbine power plants, known as Rankine Cycles that are also capable of high efficiency and lower emission. In the world scale, much attention on searching for higher efficiency and lower emissions has been directed toward second-generation technologies2.

In view of the possible near-term benefits, ADB has funded this energy efficiency technical study of UB thermal power plant #4. The purpose of this study is to establish, through engineering analysis, the most promising energy efficiency raising potentials available through improvements in the energy production cycles of the TES#4.

Using the information on the measures that are taken to improve plant efficiencies in cases in the western countries, the potential options that could be implemented on the Mongolian brown coal-fired plant TES#4 are summarized in the Table 1.1.1. They have used the assumptions that electricity consumption, the total fuel heat rate and efficiency of the TES#4 are 2150 GWh, 7016,7 GWh and 30,64%, respectively, at the present level.

2 These technologies include coal gasification combined cycles, fuel cells that utilize hydrogen derived from coal gasification or natural gas fuel, and other advanced power plant systems that in addition to power generation may also generate chemical products.

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Table 1.1.1 - Avoided CO2 Emissions from the

Energy Efficiency Options (TES#4)

Action

Incr

ease

d ef

ficie

ncy

%

Red

uctio

n of

Fu

el h

eat r

ate

GW

h/yr

Avo

ided

Coa

l C

onsu

mpt

ion

103 to

ns/y

r

CO

2 em

issi

on

redu

ctio

n 10

3 tons

/yr

CO

2 em

issi

on

redu

ctio

n co

st

103 U

S$/y

r

1 Cooling tower film pack 32,6 423,9 104,40 167,0 835,21

2 Coal drying with heat recovery 35,14 898,5 221,31 354,1 1770,49

3 On-line condenser cleaning system 31,48 187,2 46,11 73,8 368,91

4 High efficiency turbine blades 31,62 217,5 53,56 85,7 428,49

5 Extra air heater surface in the boiler + add. soot blowers

32,74 450,0 110,85 177,4 886,79

The above options are all taken to improve plant efficiencies in cases in the western

countries and a soundly based engineering study with costs would need to be undertaken for a specific heat and power station such as TES#4 (see the above Table 1.1.1).

Low rank coals in Mongolia have relatively high ash and moisture content. Coal cleaning has not been performed either at the mines or at the power plants. Coal mining and cleaning techniques can reduce the levels of trace elements that are contained in the ash after combustion and reduce coal transport costs. Presently, the permit system for sources of pollutants from power plants is not in force in Mongolia and the power plants are buying the relevant coal from the certain mines with designated coal, without considering moisture and ash contents, or coal washing or coal sizing or consistency issues either.

The modernization concept of the performance of older steam turbines results in an increase in efficiency to a level comparable with that of new turbines, while maintaining the main dimensions and steam parameters of the existing turbines. The preferred solution is replacement of the components in the flow path including the inner casings with components of more advanced design for TES#4. This will offer the greatest potential for increasing turbine efficiency and output. New blading, modified seals and enlarged cross sections are the major issues (row 4 of the Table 1.1.1 shows estimates of the potential savings).

1.2 Energy Sector of Mongolia

As stated in the “Mongolia: Sustainable Energy Sector Strategy” (2002), the actions needed to improve energy efficiency and establish a legal framework for energy conservation include the creation of a legal environment for energy efficiency3 and improvements of efficiency in the thermal power plants and heat only boilers, including necessary rehabilitation work.

Through improvements in energy efficiency, Mongolia can reduce its reliance on

imported energy sources, reduce costs, mitigate the environmental impacts of energy use and increase its energy security. The use of energy efficient products and processes will

3 In this document it is stated that key actions needed are to develop, adopt and implement the energy efficiency law and a national program on energy efficiency.

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yield additional benefits to Mongolia’s national energy production and delivery infrastructure by increasing productive activities.

GDP and Energy Consumption. Figure 1.2.1 shows the trends in development of GDP and primary energy consumption in Mongolia. The specific GDP per head of population, in constant 1995 prices, has been continuously increasing, from 264'600 Tg in 2000, to 308'400 Tg in 2004, at an average rate of +3.55% p.a.. Total GDP, combining the population growth and the productivity growth (GDP per head of population), has grown from 2000 to 2004 by an average rate of 4.64 % p.a., from 632'521 million Tg in 2000 to 776'902 million Tg in 2004 (at constant 1995 prices).

Figure 1.2.1 - Development of GDP per Person and Electricity Use per GDP

The relationship between real GDP and total energy requirements is best defined by energy intensities4. The less energy intensive the economy is, the more efficient it is. Therefore, energy efficiency improvement options are being developed that could be implemented in the generation, transmission, distribution and end use of electricity and heat.

Energy Balance. As shown in Table 1.2.1 - Energy Balance, the energy intensive consumers, i.e. the main areas to focus energy efficiency product applications on in the present near term years, are in the industrial sector and communal and multifamily apartment buildings are the use of both electricity and heat and the energy efficiency improvements that are needed in the production of electricity and heat.

Most of the main energy-using industries are located on industrial estates surrounding power stations in the main cities. Smaller industries located away from the main power stations have their own boilers but, in general, the use of combustion processes within a factory is rare. In 2003 just over 3’137.7 million kWh (90%) of electricity were generated in Mongolia and a further 171.3 million kWh (10%) were imported. This electricity

4 Energy Intensity: The relationship between total energy requirements per real GDP. The lower the energy uses for the production of a unit of GDP, the less energy intensive the economy.

GDP per Person; Electricity Use per GDP

0

1000

2000

3000

4000

5000

6000

1990 1995 2000 2005 2010 2015 2020

GDP1'000Tg/10pop. "Optimistic" GDP1'000Tg/10pop. "Medium"GDP1'000Tg/10pop. "Cautious" kWh / GDP mio Tg.

GDP 1'000 Tg. / 10 Persons

kWh / GDP mill. Tg.

7

energy was used to cover the transmission and distribution losses and internal uses of the Energy Authority (33.5%), industry (42%), service and apartment buildings (16%) and agriculture and transport (4%). As for heat, in 2003, 2288,50 thousand Gcal of gross heat generation was consumed by industry (32%), 2777,20 thousand Gcal was used in commercial, service buildings and apartment buildings (39%), and 214.4 thousand Gcal was lost in heat transmission (3%).

There is significant potential for energy savings through the use of energy conservation

measures in the industrial sector, including the energy industries, and the service sector and residential buildings. These include the energy savings potential for motors, lighting, heating and ventilation systems and industrial processing, and improvements in the building fabric and services.

Table 1.2.1 - Mongolia: Energy Balances

ELECTRICITY BALANCE, GWh 2000 2001 2002 2003 Resources- Total 3127,00 3213,00 3279,00 3309,00 100,00% 100,00% 100,00% 100,00%Gross generation 2946,00 3017,00 3111,70 3137,70 94,21% 93,90% 94,90% 94,82%Import 181,00 196,00 167,30 171,30 5,79% 6,10% 5,10% 5,18%Distribution 3127 3213 3279 3309Consumption 1910 1948 2031,7 2194,6 61,08% 60,63% 61,96% 66,32%Of which: 100,00% 100,00% 100,00% 100,00%Industry & construction 1182,00 1204,00 1260,10 1361,10 61,88% 61,81% 62,02% 62,02%Transport & communication 79,00 87,00 84,70 91,50 4,14% 4,47% 4,17% 4,17%Agriculture 21,00 17,00 22,00 23,80 1,10% 0,87% 1,08% 1,08%Communal service buildings and apartment buildings

463,00 476,00 487,10 526,10

24,24% 24,44% 23,97% 23,97%Other 165,00 164,00 177,80 192,10

8,64% 8,42% 8,75% 8,75%Losses in transmission and distribution

576,00 603,00 582,80 489,20

18,42% 18,77% 17,77% 14,78%Station internal use 616,00 644,00 649,00 618,40 19,70% 20,04% 19,79% 18,69%Export 25,00 18,00 15,50 6,70 0,80% 0,56% 0,47% 0,20%

HEAT BALANCE, 1000 Gcal 2000 2001 2002 2003 Gross generation 6885,40 6597,20 6867,60 7133,30 100,00% 100,00% 100,00% 100,00%Station internal use 138,00 59,60 144,90 335,50 2,00% 0,90% 2,11% 4,70%Consumption-Total 6747,40 6537,60 6722,70 6797,80 98,00% 99,10% 97,89% 95,30%Of total consumption: Industry and construction 2620,10 2343,70

2428,50 2288,50

38,83% 35,85% 36,12% 33,67%Transport and communication 410,60 485,60 419,60 443,50

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6,09% 7,43% 6,24% 6,52%Agriculture 33,30 36,50 36,20 40,50 0,49% 0,56% 0,54% 0,60%Communal service buildings and apartment buildings

2655,10 2990,50 2843,10 2777,20

39,35% 45,74% 42,29% 40,85%Other 794,90 562,80 841,80 1033,70 11,78% 8,61% 12,52% 15,21%Losses (T&D) 233,40 118,50 153,50 214,40 3,46% 1,81% 2,28% 3,15%

Generation Mix in Mongolian Power Systems. Mongolia’s electricity supply system essentially consists of three separate, independent grids. In addition there are two-isolated aimag centres not yet connected to the three-grid system, each with a power plant supplying small local networks. Some 600-diesel units are used for off-grid rural soum (village) centre power supply.

The largest of the three grids, which covers the area where most of the country’s population lives, is the Central Energy System or CES. The CES has presently a gross electricity demand of around 520 MW (including the Erdenet Copper Mine load and including power station internal usage), which accounts for approximately 95% of the total load in the country. The other two grids cover the western and eastern part of Mongolia and are very small in comparison with CES. The Western Energy System (WES) covers the aimags of Uvs, Bayan-Ulgiy and Khovd in the Altai Region with a total demand of about 8 MW and the Eastern Energy System (EES) serving the two eastern aimags of Dornod and Sukhbaatar with a total demand of about 11 MW.

The main problems in the CES are (i) the largest generation unit at 100 MW provides about 20% percent of winter average load - its sudden stoppage leads to big power deficit; (ii) the power generating units have lower generator capacity and they lack automatic generation controls - they are not able to respond quickly enough to changes in load demands; (iii) self-generation or captive power and peaking capacity are virtually non-existent; (iv) deficiencies are covered by selectively curtailing load on a rotating basis and/or by buying power and energy from Russia.

For Mongolia, the most technically and financially viable solution in the near term is

the energy conservation programs, including energy efficiency improvements in the power plants themselves.

Central Energy System (CES) In the CES area the total installed capacity is 786.3 MW compared to a peak demand of about 475 MW. It is provided by the CHPs in Ulaanbaatar, Darkhan and Erdenet (Table 1.2.2).

Table 1.2.2 - Existing Combined Heat and Power Plants in CES

Power & Heating

Plant

Installed Capacity

(MWe)

Available Capacity

(MWe)

Capacity Boilers (MWth)

District Heating (MWth)

Indus. Steam (MWth)

Commissioning Year

Ulaanbaatar TES 2

21.5 17.6 80 43 58 1961 – 1969

Ulaanbaatar TES 3

148.0 105.1 1’448 562 105 1968 – 1982

9

Ulaanbaatar TES 4

540.0 432.0 2’450 918 29 1983 – 1991

Darkhan 48.0 38.6 477 210 49 1966, 1986 Erdenet 28.8 21.0 318 140 24 1987 - 1989 Total CES 786.3 614.3 4’773 1’873 265 -

All five old coal-fired power stations in the CES grid are of Russian design. They are

cogeneration plants for production of base load electricity, hot water for district heating and process steam for industry. The CES is unable to meet the daily system demand with these plants due to their poor peaking capability.

Outages reduce the actual power delivery by about 14-18 %. In addition, the CES

uses 22% of the gross generation for its own use during the winter and this amount is very high. Most of the combined heat and power (CHP) plants operate with de-rated capacity due to the fact that the coal quality is much below that of the design coal for these boilers. The situation is aggravated by coal supply and spares parts problems.

A serious aspect of the system is its age. The remaining lifetime of the power plants

is only 12 years on average with the Ulaanbaatar Power Plant No. 4 (TES 4) capable of operating possibly for 15 years more. It is apparent to professional circles that major refurbishment must be considered in the short-term and medium term replacement of the generating capacity has to be planned for soon.

Rehabilitation projects on the CHPs TES 3, TES 4 in Ulaanbaatar, the Darkhan CHP

and the Choibalsan have been carried out and are partly financed by loans from various donors. A major part of these rehabilitation projects was devoted to boiler refurbishment, which improved considerably the reliability of operation. A new rehabilitation project is ongoing on TES 4 with a 50 million US$ loan from Japan.

Table 1.2.3 - Boilers of the Existing CHPs in Mongolia

CHP Boiler Type Capacity t/h

Steam

Number of

boilers

Boilers Rehabilitation

Year UB TES 4 Single drum, pressurised

circulation, direct firing system 420 4 1997-1999

UB TES 4 Single drum, pressurised circulation, Indirect firing system

420 4 2002-2006

UB TES 3 Single drum, natural circulation, direct firing system

220 4 1996-2000

UB TES 3 Single drum, natural circulation, Indirect firing system

220 3 -

UB TES 3 Single drum, natural circulation, direct firing system

75 5 -

UB TES 3 Fluidised bed combustion 75 1 1/1999-2001 UB TES 2 Fluidised bed combustion 35 1 1 / 2001 UB TES 2 With chain grate 35 1 - UB TES 2 Single drum, natural circulation,

direct firing system 75 2 -

10

Darkhan Single drum, natural circulation, indirect firing system

75 9

3 / 1995-1997

Erdenet

Single drum, natural circulation, indirect firing system

75 6

Table 1.2.3 above presents an inventory of all CHP boilers in the CES. It gives their

main features and their steam output. It also shows those that have been rehabilitated. Table 1.2.4 presents an inventory of all CHP turbines in the country. It shows their main features, their power generating capacity and if they have been rehabilitated.

Table 1.2.4 - Turbine Sets in Existing CHPs in Mongolia

CHP Turbine Type Capacity MWe

Number of

Turbines

Turbine Rehabilitated

Year UB TES 4

With extraction for district heating

100 3 -

UB TES 4

With extraction for process steam and district heating

80 3 3 2001 - 2006

UB TES 3


25 4 2 1998

UB TES 3


12 4 -

UB TES 2

With extraction for process steam and district heating Back pressure

12 6

3.5

1 1 1

- - -

Erdenet With extraction for process steam and district heating Back pressure

12

8.4

1

2

- - -

Darkhan With extraction for process steam and district heating

12 4 1 1997

The in-station auxiliary power and heat consumption are very high in the existing

CHPs and amounts on average to about 19% of the gross generated electricity and to about 10% of the gross generated heat (Table 1.2.5). These figures are very high compared to international standards and add to the extremely low plant efficiencies for power generation and overall fuel utilisation values when considering cogeneration. Net electricity export compared with the gross generation is on average for all stations only 78%, or self-use of 22%. A normal expected value for self-use is in the range of 10-12% for a coal-fired CHP operation.

Table 1.2.5 - Power Plants of CES: Internal Use of Electricity, %

1997 1998 1999 2000 2001 2002 2003 2004 (2005) TES#2 17.79 18.54 17.89 19.56 18.68 18.34 18.22 17.76 17.76 TES#3 31.62 31.62 28.15 27.83 25.60 25.40 24.6 25.57 24.0 TES#4 20.25 19.91 19.48 20.11 20.71 19.89 18.27 17.17 16.6 Darkhan TES

19.55 19.55 20.22 19.06 17.67 17.75 18.78 18.79 17.8

11

ERDENET TES

28.04 28.30 27.33 25.38 25.62 25.84 25.86 23.82 23.8

CES 22.00 22.00 21.00 22.00 22.00 21.00 19.78 19.08 18.3

The fuel utilization efficiency, defined as net energy (electricity and heat) export

compared to total fuel heat (LHV) input to the boiler is in the range of 40-70% for all stations, with the average in the magnitude of only 55% [Energy master plan, 2001]. In a modern CHP scheme figures of 70-90% are achievable. Reasons for the low total heat utilization are: low boiler efficiencies; low steam/water cycle efficiencies; excessive own consumption of heat and power; low condensate return and high-energy (radiation, leakage, etc) losses.

Loss of condensate is in the range of 10-30%, with the average in the magnitude of

15%. Since makeup water is scarce, this is contributing negatively to the operation cost of the stations. The circulating water temperatures of the district heating systems are typically in the magnitude of 85 (supply) to 55 (return) °C. Commonly supply temperature is expected between 110-140 °C and return temperatures between 70-90 °C [Energy Master Plan, 2001]. The electrical efficiencies of the all power plants in the CES grid are given in the Table 1.2.6.

Table 1.2.6 - CES: Electrical Efficiencies of the Power Plants

1997 1998 1999 2000 2001 2002 2003 2004 TES#2 28.4 28.0 32.6 28.4 28.9 28.9 29.0 29.1 TES#3 20.4 21.7 23.9 27.7 26.8 25.6 28.1 28.2 TES#4 29.7 30.4 31.0 31.6 32.3 31.6 33.9 34.3 Darkhan TES 28.0 26.3 29.3 27.2 29.5 29.4 29.5 29.6 ERDENET TES

29.1 32.1 29.5 32.5 32.9 33.2 33.1 33.9

CES 14.9 14.7 14.5 14.6 16.3 16.3 15.5 17.7

Energy Generation in CES. Generation, peak loads and export and import of

electricity for the CES grid are given in Table 1.2.7. From this table, the largest power plant is the combined heat and power plant (TES#4) and it produces 56.6 % of total gross generation of the power system.

Table 1.2.7 - Main Energy Indices of CES Operation, GWh

1999 2000 2001 2002 2003 2004 TES#2 (CHP) 94,3 94,2 86,6 105,6 107,2 105,6TES#3 (CHP) 515,9 529,4 530,7 543,8 550,0 565TES#4 (CHP) 1825,3 1909,6 1958,1 2001,7 2009,2 2150Darkhan TES (CHP) 196,1 199,9 205,8 223,8 229,4 238,9Erdenet TES (CHP) 108,6 112,7 116,7 128,6 131,9 135,5Total gross generation 2740,2 2845,8 2897,9 3003,5 3027,7 3195,0Import 194,8 151 156,8 116,3 131,1 Export 24,9 24,9 17,8 8,1 6,7 Total demand 2910,1 2971,9 3036,9 3111,7 3152,1 3198,4Peak load, MW 499 526 538 532 539 545Total demand, GWh 2910,1 2971,9 3036,9 3111,7 3152,1 3198,4

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Typical daily load curves of the CES and its power plants are given in the Figure 1.2.2. From the load curves, it can be seen that TES #4 covers 54-66 % of the total demands in the CES grid.

Figure 1.2.2 - Typical Load Curves of CES Grid

Typical Daily Load Curve, Jan

0

100

200

300

400

500

600

1 3 5 7 9 11 13 15 17 19 21 23

hour

MW

import /export/-/PP#4ErdPPDarPPPP#3PP#2

Typical Daily Load Curves, April

0

100

200

300

400

500

1 3 5 7 9 11 13 15 17 19 21 23

hour

MW

import /export/-/PP#4ErdPPDarPPPP#3PP#2

Typical Daily Load Curve, Jul

050

100150200250300350400

1 3 5 7 9 11 13 15 17 19 21 23

hour

MW

Import /export/-/PP#4ErdPPDarPPPP#3PP#2

13

Typical Daily Load Curves, Sep

0

100

200

300

400

500

1 3 5 7 9 11 13 15 17 19 21 23

hour

MW


Typical Daily Load Curves, Dec

0

100

200

300

400

500

600

1 3 5 7 9 11 13 15 17 19 21 23

hour

MW


The specific fuel consumption and coal calorific values are given in the Table 1.2.8.

Table 1.2.8 - Specific Fuel Consumption and Calorific Values

2000 year 2001 year 2002 year fuel specific consumption

fuel specific consumption


for electrical g/kWh

for heat kg/Gcal

calorific valueQHP-

kcal/kgfor

electrical g/kWh

for heat kg/Gcal

calorific value QHP-

kcal/kg for

electrical g/kWh

for heat kg/Gcal

calorific valueQHP-

kcal/kg

TES#2 574,26 184,84 3274 597,22 187,6 3313 643,53 184,28 3409,5TES #3 LP 515,3 197,6 3265 472,7 192,1 3406,1 448,0 198,8 3275,7TES #3 HP 475 196,4 3265,0 463,5 192,9 3406,1 489,5 195,2 3275,7TES #4 388,93 184,12 3360,1 388,02 183,78 3240,8 389,33 184,09 3216,7Darkhan TES 451,9 168,8 3544,8 416,54 173,36 3826,2 418,46 187,27 3733,0Erdenet TES 340,79 SYSTEM 414,3 185,4 3371,8 408,57 3364,8 413,49 185,65 3314,6

14

2003 year 2004 year 2005 year fuel specific consumption



for electrical g/kWh

for heat kg/Gcal


kcal/kgfor

electricalg/kWh

for heat kg/Gcal


kcal/kg for

electrical g/kWh

for heat kg/Gcal


kcal/kg

TES#2 649,34 184,11 3225,4 638,85 189,78 2938,0

TES #3 LP 190,5 3432,8 539,29 207,70 3378,0

TES #3 HP 460,1 191,1 3432,8 424,47 192,50 3378,0

TES #4 364,59 182,48 3251,4 355,92 180,3 3161,0

Darkhan TES

416,49 187,59 3836 392,45 185,61 4036,1

Erdenet TES

343,12

SYSTEM 395,49 184,79 3370,8 388,00 164,07

1.3 Current Status of Power Plant TES#4 Overview. The combined heat and power plant #4 (TES#4) was constructed under

the design of the former USSR's equipment suppliers. The plant consists of 74 buildings and facilities located 3-20 km from the plant and includes an ash pond, water supply pump station, service building, administration building, laboratory and test center etc. occupying 12.8 hectares (Figure 1.3.1). The station employs about 1400 people.

Thermal Power Plant #4 in Ulaanbaatar consists of 3x100 MW steam turbine

generator units (#2, #3 and #4) and 3x80 MW steam turbine generator units (#1, #5 and #6). The steam turbine generator units are connected to eight (8) boilers through a common main steam header. The first steam turbine generator unit was commissioned in 1983 and the last unit in 1991.

The current combined maximum continuous rating of all the eight steam turbine

generator units is 540 MW. The gross energy generated in 2004 was 2150,0 GWh, out of which, about 17,7% was used internally for auxiliary equipment power consumption. The station supplies power to the CES grid at 220 kV and 110 kV as well as providing hot water to the city's space heating system when needed during the heating season (September 15 to May 15) and steam to adjoining industries.

The UB TES #4, which is the major power station of the country, has been partly

rehabilitated under a Japanese soft loan from 1998-2006. In Phase 1 of the project, boiler units #1, #2, #3 and #4 have been rehabilitated, and new coal mills and new control systems installed. This has resulted in remarkable improvements especially in terms of reduction in fuel consumption together with emission control. The project also significantly contributes to atmospheric pollution control. The emission control of CO2 is one of the most urgent global issues and will be regulated more strictly in Mongolia in the future. To cope with this urgent need, the lasting contribution of the project to the emission control is indispensable.

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Figure 1.3.1 - General Layout of the TES#4

16

The components of the rehabilitation project of the 4th Thermal Power Plant in Ulaanbaatar, Phase II5, sponsored by Japan Bank for International Cooperation (Loan agreement MON-P6, March 26, 2001), are (i) Conversion to direct firing system for boiler #5 through #8, (ii) Rehabilitation of controls and instrumentation for boiler #5 through #8, (iii) Replacement of boiler tubes (super-heater, economizer, etc), (iv) Replacement of excitation equipment for power generator (#1 through #4). It is expected that the planned measures will increase the available capacity of the plant by about 46 MW. Furthermore it can be assumed that the plant will not need to be retired before 2020, if a thorough maintenance and overhaul program is carried through after rehabilitation. A certain de-rating, however, will have to be considered for the last years of the forecasting period.

Steam Turbine Generator Units. There are 4 generators - 2x80 MW & 2x100 MW @ 10.5 kV stepping up voltage through 4x125 MVA, 10.4 kV/242 kV + 2x2.5% unit transformer, and 2 generators 1x80 MW & 1x100 MW @ 10.8 kV stepping up voltage through 2x125 MVA, 10.5 kV/121 kV + 2x2.5% unit transformers (Table 1.3.1-1.3.3).

Table 1.3.1 - Present Status of Generators

Ulaanbaatar TES#4

Type Commissioningyear

Year of last

major overhaul

Capacity Present Status

1 TVF-120-2U3

83.10.12 2000-11 80

2 TVF-120-2U3

84.11.26 2000-10 100

3 TVF-120-2U3

85.12.27 1995-06 100

4 TVF-120-2U3

1998-06 100

5 TVF-110-2U3

83.11.18 1996-03 80

6 TVF-110-2U3

1999-01 80

Generator: Minor troubles such as burnout of metal, leakage of oil have occurred. Regular checking is required. Exciter: The exciting systems have been replaced by the Japanese loan project.

The first steam turbine generator Unit #1 of 80 MW and Units #2, #3 and #4 of 3x100 MW nominal power output were commissioned during 1983-86 and the last 2x80 MW (Units #5 and #6) were commissioned during 1990-91, all with Russian support. The current maximum continuous rating of each of these steam turbine generator units is 80 MW and 100 MW, as applicable.

The normal loading/ unloading ramp rates are 15 MW/min for 80 MW units and 10 MW/min for 100 MW units. The emergency loading/ unloading ramp rates are 20 WM/min for all the units.

5 Contract amount 6’139,0 million Yen, 0,75%p.a, 40 years w/grace period of 10 years from JBIC

17

Table 1.3.2 - Present Status of Steam Turbines

Type Commissioning year

Year of last

major overhaul

Capacity Present Status

1 PT-80-130 1983,1 2000,06 80MW

2 T-100-130 1984,11 2000,05 100MW

3 T-100-130 1985,12 1995,06 100MW

4 T-100-130 1986,12 1998,06 100MW

5 PT-80-130 1990,02 1996,03 80MW

6 PT-80-130 1991,12 1999,01 80MW

There are no specific problems and renovation is not necessary for the casing, rotor, bearing pedestal, nozzle, governor and emergency governor. Periodical inspection only needed.

Two major equipment failure incidents regarding the steam turbine generator units

were reported in the past: Unit #1 shaft was broken, and Unit #5 shaft became warped in service. In both cases the parts were shipped to the Original Equipment Manufacturer in Russia for repair. The cause of these failures was not disclosed.

Table 1.3.3 - Specifications of the Steam Turbines

Manufacturer USSR Energomach Export

USSR

Type of steam turbine (Non-reheat, condensing)

Tandem close coupled Triple tandem compound

Nominal Output 80 MW 100 MW Rated Output 80 MW 110 MW Maximum Output 100 MW 120 MW Steam Pressure 130 kgf/sq.cm(12.7 Mpa)(before stop valve)

Live Steam condition

Steam Temperature 555 deg.C (before stop valve) Live steam flow Max. 470 t/h Max. 485 t/h, Rated 480 t/h

Flow Max. 220 t/h Max. 325 t/h Turbine Exhaust Pressure Design 0.057 kgf/cub.cm (0.0056 Mpa)

Cooling water temp. /rated flow 20deg.C/8,OOOcub.m/h 20deg.C/16,000cub.m/h Rotation speed 3,000 rpm 3,000 rpm

Max. flow 300 t/h Rated flow 185 t/h

Process steam

Rated pressure 13.0 kgf/cub.m (1.275 Mpa)

Upper district heating

1.0 kgf/sq.cm 0.6-2.5 kgf/sq.cm Rated pressure in heating steam extraction point Lower district

heating 0.35 kgf/sq.cm 0.5-2.0 kgf/sq.cm

Load on district heating extraction point

Rated/Max 69/104 Gcal/h 175/184 Gcal/h

Feed water system 249 deg.C 4LP+D+3HP 232 deg.C 4LP+D+3HP

18

The control panels of the steam turbine generator Units #1-3 are installed in one control room shared with boilers #1-4 controls and the control panels of the steam turbine generator Units #4-6 are installed in another control room shared with boilers 5-8 controls. Most of the steam turbine generator units' controls are original, and some of the controls have been partially refurbished.

Boilers. There are eight (8) boilers (Russian made, BKZ-420-130-10C type), each

with a capacity of 420-t/h steam (140 kg/cm2, 560°C) output, the first six boilers were commissioned during 1983-87 along with the first four steam turbine generator units and the last two boilers were commissioned during 1990-91 along with the last two steam turbine generator units (Table 1.3.4 and 1.3.6).

Table 1.3.4 - Rehabilitated and Rehabilitating Boilers

Type Commissioned year

Design Capaci

ty

Type of firing

system Design

coal Rehabilitated by the Japanese Financing

1 BKZ-420-140 1983,1 420 Direct firing Baganuur Phase I 1999 2 BKZ-420-140 1984 420 Direct firing Baganuur Phase I 1999 3 BKZ-420-140 1984,1 420 Direct firing Baganuur Phase I 1998 4 BKZ-420-140 1985,1 420 Direct firing Baganuur Phase I 1999

5 BKZ-420-140 1986,1 420 Indirect firing Baganuur Phase II 2004-2006


7 BKZ-420-140 1990 420 Indirect firing Baganuur Phase II 2004-2006


Usually four boilers are in service with one of them as hot standby. During peak

load, five boilers could be in service. The original boiler design incorporates corner fired (4x3 burners) units, with direct

fired Boilers #1-4 serviced by four (4) vertical bowl mills each, and indirect fired Boilers #5-8 serviced by two horizontal ball mills each. All indirect fired boilers are being converted to direct firing, which will be completed by 2005.

The coal to the power plant6 is the B2 type supplied from Baganuur and Shivee

Ovoo coal (3100-3500 kcal) mines. This coal has less than 0.6% sulphur. In addition, M-40 type heavy oil fuel at a consumption (for each steam generator) of 75-80 tons heavy fuel per hour and 25 tons per hour of light oil are used in the starting period of the boilers from the cold reserve. Coal and oil reserves are maintained with open-air coal storage yard of 240000 tons, heavy oil tank of 5000 cubic meters, and light oil tank of 700 cubic meters.

Electrostatic precipitators (ESPS) are provided for removing the fly ash in the flue

gases from the boilers.

The upgrade of the original Boilers #1-4 controls to DCS control was completed in 2003. The upgrade of Boiler #5-8 is currently in progress and will be completed by 2006. 6 Per hour: The TES#4 consumes 282 tons of coal, 1531 tons of water and generates 242 MW electricity and 249,4 Gcal heat (239,7 Gcal in water and 9,4 Gcal in steam), while consuming 75 tons of Shiyee-Ovoo and 66 tons of Baganuur coal per hour.

19

Table 1.3.5 - Specifications of the Boiler

Manufacturer

USSR

Type Indoor, radiant, single drum, natural circulation type

Unit No. Unit 1 to 8 Boiler Steam Boiler Capacity 420 t/h (Superheater Outlet) Condition Steam Pressure 140 kgf/cm2 (14Mpa) (Superheater Outlet) Steam Temperature 560 deg.C (Superheater Outlet) Fuel Used Description Mongolian Coal (Baganuur, Shivee-ovoo) High Calorific Value 4,000 kcal/kg (956 kJ/kg)-3,000 kcal/kg Type Super heater Pendant Type Boiler Furnace Single Furnace, Water Wall Air Heater Tubular Type Coal Burner (Numbers) Corner Firing (4x3 stages) ESP Electrostatic Type Ash Treatment System Slurry Ash with water circulation system Coal Pulverizer

(Numbers) Horizontal tube mill with flue gas drying system (2)

Pulverized Coal Firing System

Semi-direct storage bin (Blowing by primary fan)

Ventilation System Balanced Draft (Note) Coal pulverizing and pulverized coal firing systems for the Boiler Nos.1 to 4 are now under refurbishment to a direct firing system.

20

Figure 1.3.2 - Coal Feed and Boiler

21

Figure 1.3.3 - Direct Firing Mill System

22

Table 1.3.6 - Characteristics of the Boilers

Description Unit Design Max Operational Steam Pressure of drum ata 160 160 160 Temperature after super heater primary stage 0C 393 420 393 Temperature after super heater secondary stage 0C 452 460 452 Pressure after super heater secondary stage ata 145 Flow t/h 420 Feed water

Temperature inlet ECO1 0C 230 346

Temperature outlet ECO1 0C 245 346

Temperature inlet ECO2 0C 249 349

Temperature outlet ECO2 0C 270 349 Pressure ata 220 167 Flow t/h Flue gas

Temperature inside Furnace 0C 1603 1604 1603 Temperature outlet Super heater primary stage 0C 521 560 521 Temperature outlet Super heater secondary stage 0C 827 929 827 Temperature outlet Air Heater secondary stage 0C 669 730 669 Temperature outlet Economizer secondary stage 0C 755 838 755 Temperature outlet Air Heater primary stage 0C 180 191 180 Temperature outlet Economizer primary stage 0C 310 417 312

Temperature outlet 0C 132 141 132 Coal Consumption t/h - 75-85 tonne Capacity of coal pulverisation mm2 35% R90-30-35% Flue gas analyzator O2 4-6% 4-6% 4-6%

CO 20mg/m3 20mg/m3 20mg/m3

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The present status of the main components of all boilers is given in Table 1.3.7.

Table 1.3.7 - Present Status of the Components of Boilers

Existing conditions with recent rehabilitation. Drum In good condition and renovation is not necessary. Water Drum Non-existence of the Water Drum (Existing only tube header) Furnace Tubes were replaced in Japanese loan project.

Header is in good condition. Super Heater Header is in good condition. Tubes were replaced in Japanese loan project. Re-heater Non-existence of Re-heater. Economizer Header is good condition.

Tubes (#6,7) were replaced in Japanese loan project. Valves Safety, steam and feed water valves are in good condition. Pumps Feed water circulating and boiler feed pumps are good condition. FDF To be renovated by the Plant’s own finance. GRF To replace the fan by the plant’s own finance. IDF To be renovated by the plant’s own finance. PGF Replaced by the Japanese loan project (boilers #5,6,7,8). Burner Replaced by the Japanese loan project (boilers #5,6,7,8).

The specifications and present status of the auxiliary equipment of the boilers are given in the Table 1.3.8.

Table 1.3.8 - Characteristics and Present Status of the Auxiliary Equipment

Ulaanbaatar - TES#4: Auxiliary Equipment 1

No of boiler

Year of commissi

oning Type Capacity Capacity of

motor Present status

1 1983 DOD31.5 934*103 - Good 2 1984 DOD31.5 934*103 - Good 3 1984 DOD31.5 934*103 - Middle 4 1985 DOD31.5 934*103 - Middle 5 1986 DOD31.5 934*103 200 Good 6 1987 DOD31.5 934*103 1998 Good 7 1990 DOD31.5 934*103 Good In

dice

d dr

aft f

an

8 1991 DOD31.5 934*103 - Good 1 1983 VDN-32B 490*103 - Good 2 1984 VDN-32B 490*103 - Middle 3 1984 VDN-32B 490*103 - Middle 4 1985 VDN-32B 490*103 - Middle 5 1986 VDN-32B 490*103 2000 Good 6 1987 VDN-32B 490*103 1998 Good 7 1990 VDN-32B 490*103 Middle Fo

rced

dra

ft fa

n

8 1991 VDN-32B 490*103 1999 Middle

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No of boiler

Year of commissioni

ng Type Capacity Year of last

major overhaul Present state of operation

1 1983 EGA2 10.5 t/h - Middle

2 1984 EGA2 10.5 t/h - Middle

3 1984 EGA2 10.5 t/h 1998 Middle

4 1985 EGA2 10.5 t/h - Good

5 1986 EGA2 10.5 t/h - Good

6 1987 EGA2 10.5 t/h - Good

7 1989 EGA2 10.5 t/h - Bad

Ash

hand

ling

syst

em

8 1991 EGA2 10.5 t/h - Good


Equipment Boiler Year of

commissioning

Type Capacity Last

major overhaul

year

Present status

1 1999 SM-19 27.5t/h - Normal

2 1999 SM-19 27.5t/h - Normal

3 1998 SM-19 27.5t/h - Middle Roller mill

4 1999 SM-19 27.5t/h - Middle

Ball mill 5 1985 SHBM 41.6 t/h 2000 Good

ShBM-320/675 6 1986 SHBM 41.6 t/h 1998 Middle

ShBM-320/675 7 1990 SHBM 41.6 t/h Bad

ShBM-320/675 8 1991 SHBM 41.6 t/h 1999 Middle

Exhaust fan 1 1999 klla-90-AK 39.48m3/s Normal

2 1999 klla-90-AK 39.48m3/s Normal

3 1998 klla-90-AK 39.48m3/s Middle

4 1999 klla-90-AK 39.48m3/s Middle

MV-20A 5 1985 MV Middle




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Electrical. All the steam turbine generators (STG) are of capacity 100-125 MVA at 10.5 kV, which is stepped-up to 220 kV from Units #1-4 and to 110 kV from Units #5-6. There is a 125 MVA autotransformer interconnecting 220 kV and 110 kV lines. The 110 kV line is also connected to TES #3.

All protection relays are of original Russian design. The SCADA unit (Honeywell)

was installed in 1999. There is no remote control of circuit breakers from the NDC (National Dispatch Centre) control room.

As for the 110 kV circuit breakers (CB), one SF6 CB (GE Alsthom make) was

already installed in 1998 with USAID financial support and the remaining 14 CBs were replaced with Siemens CBs during 2003-2004.

As for the 220 kV CBs (13), one was replaced with GE Alsthom and two SF6 CB

(XI'AN HV Apparatus make) were already installed in 2002. All remaining 220 kV oil-filled circuit breakers are of old Russian designs, which will be replaced with SF6 CBs (with SIDA aid) in the near term.

Table 1.3.9 - Present Status of Electrical Equipment

Existing conditions with rehabilitation needs Main Transformer The bushing of No.6 main transformer has been damaged and requires

repair or replacement. Circuit Breaker Regular maintenance is required. Oil leakage prevention measures needed. Disconnecting Switch

No specific troubles. Renovation is not required.

Condenser No specific troubles. Renovation is not required. Reactor No specific troubles. Renovation is not required. Metal Clad Switch Gear

No specific troubles. Renovation is not required.

Cable Deterioration of insulation. Regular maintenance is required.

Controls and Instrumentation. Boiler system controls are a vital part of the overall control and instrumentation of the power station and are composed of 17 automatic control loops per boiler. The drum water level and steam temperature control loops are operated in automatic control and the other 15 loops by remote manual operation.

In phase I of the Japanese soft loan project, the controls and instrumentation of the

boiler units #1 -#4 were refurbished and, presently, the controls and instrumentation of the remaining 4 boilers (#5-#8) are under rehabilitation within phase II of the Project. Before the Japanese loan project, the controls of boilers were of analogue control type from Teplovi Automatic of Moscow.

Water supply and treatment systems. There are 12 pumps for ground water collection connected with 4 pumps for delivering a total capacity of 1,260 tons water per hour to the Power Station. The ground water collection is situated about 22 kilometres from the Power Station. Typically, about 730-760t/h of water delivered to the Power Station is treated by the water treatment system (about 500 t/h are used for make-up of district heating system and about 200 t/h and above is used to make-up of the condensate loss and boiler loss makeup). Water, utilized for cooling the equipment, is used for the ash handling system.

The water purification system is a separate operating system and with 2 step sodium-cationic filters.

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Characteristics of Cooling System Description Unit Design Max Operational Water cooling system Year of commissioning 1983 Number 3 Capacity 22500m3/h Type Present operational level Temperature input oC 32 Temperature output oC 20 Efficiency Year of last major overhaul Main cooling water pump Number 6 Maker Russ Livgidromash Type Ä-12500-24 Suction pressure ata 1 1 1Speed rev/min 493 493 493Consumption kW 1000 1000 1000Type of control Remote Motor rating kW 950 950 950

Characteristics of Feed Water System Description Unit TG-1 TG-5 TG-6 Low Pressure Heater Maker Russia Type PN-130-16-10: PN-200-16-7 Year of commissioning 1983 1991 1992Number 4 4 4Year of last major overhaul 2000 1998 1999Steam Pressure Ata 10 10 10Temperature 0C 160 160 160Flow m3/h 28 28 28Water Pressure Ata 16 16 10Temperature inlet 0C 40 40 40Temperature outlet 0C 150 160 145Deaerator Maker Type Year of commissioning Number Year of last major overhaul Steam Pressure Ata Temperature 0C Flow m3/h

27

Water Pressure Ata Temperature Inlet 0C Temperature Outlet 0C High Pressure Heater Maker Russia Type PV-425-230 Year of commissioning 1983 1991 1992 Number 3 3 3 Year of last major overhaul 1991 1999 1999 Steam Pressure Ata 23/35/50 23/35/50 13/26/45 Temperature 0C 420 420 265/345/420 Flow m3/h 32 32 10.5/32/26 Water Pressure Ata 230 230 230Temperature inlet 0C 160 160 158Temperature outlet 0C 230 230 230

Characteristics of Feed Water System Description Unit TG2 TG3 TG4

Low Pressure Heater Maker Russia Type PN-250-16-7 Year of commissioning 1985 1987 Number 4 4 4 Year of last major overhaul 2000 1998 1998 Steam side Pressure ata 7 7 0.204/0.8/2.78 Temperature 0C 190 190 130Flow m3/h 17 17 22,2Water side Pressure ata 16 16 10Temperature inlet 0C 40 40 40Temperature outlet 0C 150 160 145Deaerator Maker Barnual Boiler Zavod Type DB-65-1-3 Year of commissioning 1985 1987 1992 Number 8 Year of last major overhaul 1996 1999 2000 Steam side Pressure ata 7,8 9 6Temperature 0C 172 172 170Flow m3/h Water side Pressure ata 7,8 9 6Temperature Inlet 0C 70 70 70Temperature Outlet 0C 160 160 158

28

High Pressure Heater Maker Russia Type ÏÂ-425-230 Year of commissioning 1985 1987 1992 Number 3 3 3 Year of last major overhaul 2000 1998 2000 Steam side Pressure ata 13/23/35 13/23/35 11.3/21.8/33.6 Temperature 0C 400 400 263/338/337 Flow m3/h 20 20 18.6/16.9/27.6 Water side Pressure Ata 230 230 230Temperature inlet 0C 160 160 158Temperature outlet 0C 230 230 230

Characteristics of Condenser Description Unit TG-1 TG-5 TG6 Maker Russ Russ Russ Type 80KTSS-1 80KTSS-1 80KTSS-1 Year of commissioning 1983 1991 1992Year of last major overhaul 2000 year 1998 1999Steam Flow t/h 180 227 220Pressure kgs/cm2 0,068 0,094 0,08Temperature 0C 40 60 40Water Flow t/h 8000 8000 Pressure kgs/cm2 2,4 2,4 2Temperature 0C 20 20 20Pressure loss kgs/cm2 0,8 1 1Material Shell Steel Tube

Characteristics of Condenser Description Unit TG-2 TG-3 TG4 Maker Russ Russ Russ Type KG-2-6200-1 Year of commissioning 1985 1987 Year of last major overhaul 2000 1997 1998Steam Flow t/h 325 210Pressure kgs/cm2 0,057 0,094 0,08Temperature 0C 40 60 40Water Flow t/h 16000 16000 10000Pressure kgs/cm2 2,4 2,4 2Temperature 0C 20 20 20

29

Pressure loss kgs/cm2 0,8 1 1Material Shell Steel Tube Copper

Equipment for District Heating Equipment Existing conditions with recent made rehabilitation. Pump The variable speed drives were fitted to motors by the aid project of ADB. Valves Valves are in normal condition and renovation is not required. Piping Pipes are in normal condition and renovation is not required.

Coal Supply. At present, TES #4 uses Baganuur and Shivee-Ovoo coal as the main

fuel. These two types of coal have the following characteristics. The maximum calorific value (mean) was 3,617.8 kcal/kg, while the minimum was 3,091 kcal/kg. The maximum ash content was 21.5 %, while the minimum was 10.4 %. The maximum water content was 33.3 %, while the minimum was 26.7 %. All these items have very large variation. This causes a problem for maintaining stable combustion with the existing burners with coal calorific values below 3,000 kcal/kg with high moisture content of 30 % level. The design calorific value of coal for the boilers is 3,500 kcal/kg.

To maintain stable combustion with such coal on light load, it is necessary to add

firing of high-priced heavy oil. The burning of coal with heavy oil is not only extremely unfavourable from an economic viewpoint but also detrimental to the environment, because burning both fuels at once requires stopping the operation of the electrostatic precipitators.

The Baganuur coals have relatively high calorific value and have a favorable

combustion performance. The boilers are designated to the Baganuur coal (3500kcal/kg) and the blending it with Shivee-Ovoo coal will compel the boilers to operate at below 3500 kcal/kg, while coal blending is of several options available for reducing emissions and (improve efficiency) from coal fired power plants.

The particular problems associated with the Shivee-Ovoo coal mine include the

following points (i) the coal is also known as "black brown coal" and has extremely low calorific value; (ii) as there are no cleaning facilities at the mine large rock and coal lumps are not removed; the coal also includes some iron; and (iii) the large rock and coal lumps from the hopper drop on to the conveyor belt causing damage to the conveyor.

Meanwhile, the old indirect firing system was rehabilitated with direct firing system as a result of the Japanese Loan Project (see the following table).

Coal unloading system. Coal unloading system is comprised of BPC-125 type 2 dumpers that can each dump a coal wagon of 125 tons every 5 minutes,

Coal Supply System – Related Items Existing conditions with recently completed rehabilitation. Mill Replaced by the Japanese loan project. Cyclone They are not necessary after the Japanese loan project. Coal dust They were replaced with the new firing system. Coal Feeder They were replaced with the new firing system

30

Figure 1.3.4 - Coal Handling System

31

Characteristics of Air and Dust System

Description Unit Design Max Operational Mill Maker Russ Number piece 8 Type of mill SHBM370/675 Rotation rev/min 17,2 Capacity of motor kW 32 Capacity of mill t/h 41.7t/h Average Consumption kW 1600 Capacity of bunker t 400m3 Exhaust fan Maker Russ Number 8 Capacity of motor kW 660 Rotation rev/min 1480 Consumption kW/h Capacity 150*103 m3/h Forced draft fan VDN32B Capacity of motor kW 1250/750 Rotation rev/min 750/600 Consumption kW/h Capacity 480*103m3/h Induced draft fan DOD31.5 Capacity of motor kW 1700 Rotation rev/min 495 Consumption kW/h Capacity 934*103m3/h

Ash removal system. The ash removal system: drying, reuse of water, and ash pond are located 3 km away from the plant.

Ash Treatment System Equipment Existing conditions with recently completed rehabilitation Pump Pumps are in good condition. Valves Valves are in normal condition and renovation is not required. Piping Pipes are in normal condition and renovation is not required.

1.4 Upgrades/Renovations

1.4.1 Implemented Projects

Due to a shortage of funds, spare parts and material shortages, and the irresponsibility of personnel, the plant's operation was unstable from 1991 to 1993. Numerous accidents and delays occurred; the volume of generation and financial income decreased. From 1993, foreign investment, loans and grants increased and thanks to proper allocation of domestic capital and improvement of labour discipline, initiative and active work, there were improvements in plant operation and extensive technological renovations began. As a result, the accidents and delays decreased and economic indices improved and the plant's performance stabilized, and the generation has been increasing year by year. Initially

32

100% Russian made equipment was installed at the plant. As part of the technical and technological renovation, some modern equipment has been installed from Asian and European countries.

The following are a summary of the renovation projects:

(i) The most eroded parts of all 8 steam generators' heating tubes are being replaced; the pulverized coal handling system was transferred to a fundamentally different system including a pulverized coal handling system with vertical ball mill, cyclone, separator, pulverized coal bunker, pulverized coal feeders and very long ducts to transfer the coal to its direct firing (Japan, Germany);

(ii) Control systems of the boilers were completely replaced with a new computer SCS automatic control system for boilers #1,2,3,4 and DCS control system for boilers #5,6,7,8 (Japan);

(iii) The excitation system of electric generators #1,2,3,4 were replaced with a computerized electronic system (England)

(iv) Boiler feed water pumps (#1 and #2) were replaced with pumps with variable flow, computer, full automatic control system (Germany, Denmark, China);

(v) Control and monitoring system of 8 feed water pumps was changed to computer control to ensure reliability (TES4);

(vi) Introduced a new computerized automatic control system to transport coal to the boiler coal bunker in the station premises (Czech Republic);

(vii) Replaced all calculating, technological measuring and monitoring devices with advanced, more accurate, reliable ones and renewed the laboratory and testing stands for their calibration and adjustment (TES4);

(viii) Partially replaced the plant's walls, ceilings and metal structures; (ix) Replacement of 70 percent of around 300 initially installed 6kV, 110kV and 220kB -

oil circuit breakers with Russian, German, Japanese, and Chinese vacuum and insulating gas circuit breakers to improve their reliability (under projects and TES4);

(x) Introduction of AYPA abnormal performance control and registering automatic system for all industrial electric equipment (Russia and TES4); and

(xi) Avoidance of annual shutdown maintenance as a result of development of main schemes of the plant's technological operation (TES4). Improvements in plant's operation and increase in economic efficiency as a result of

above-mentioned projects and major technical and organizational activities have resulted in; (i) increase in production, (ii) decrease in internal service electricity consumption and (iii) decrease in fuel consumption per unit electricity generation. 1.4.2 Details on Japanese Loan Projects

Phase I: Boilers #1, #2, #3, and #4. The rehabilitation work on the 4 boilers (No.l to No.4) included dismantling and reconstruction of the relevant equipment.

The scope of rehabilitation for the boilers was as follows:

1. Installation of a direct firing system with 4 sets of bowl type vertical mills together with

their pulverized coal bunkers replacing the existing 2 sets of tube type mills. The new mill system consists of 4 sets of coal feeders, 4 sets of bowl mills, 4 sets of

primary gas fans, 4 sets of seal air fans, 4 sets of lubrication systems, 400V and 6 kV switch gear and 12 sets of pulverized coal piping and hot gas ducts.

2. Replacement of existing control and protection systems for boiler and mill systems,

including control panels, control desk, control drive, measuring devices and

33

automatic protection systems. Feed water, spray and blow down control valves were also installed. Control and power cables for all measuring devices, controllers and actuators were completely replaced. Existing control and measuring devices and contactors for each boiler were replaced with the computerized automatic control system.

3. 70 % of furnace tubes were replaced with new ones. 4. The renewal of the control instrumentation for steam and water quality, secondary air

damper and associated insulation.

Phase I: Control and instrumentation. Controlling the fuel supply manually cannot regulate pressure fluctuation of main steam flow due to load changes, therefore the pressure control valves are used and a huge amount of the boiler fuel is lost. Also the forced draft fan (FDF) vanes are used to reduce airflow resulting in lower efficiency of the boilers. The operating conditions of the boilers before being rehabilitated were as follows (at normal operation of 375 t/h steam production with load change of ± 56t/h):

Drum pressure (Main steam pressure) 134 kgf/cm2 ±20.3kgf/cm2 Main steam temperature 525°C±16°C Drum level NWL ±20mmAq

After rehabilitation, the boilers will be able to operate in fully automatic condition as

follows (at normal operation of 365 t/h steam production with load range of ±32t/h): Main steam pressure 130±2.2 kgf/cm2 Main steam temperature 555±8.8 °C Drum level NWL±4mmAq Furnace pressure Set point (-3mm)±3mmAq. Flue gas O2 Set point (6%)+0.5%

It is obvious that the rehabilitated boilers can be controlled within small values of

fluctuation and huge amount of fuel savings are expected. The automatic operation of the boilers will also reduce the amount of work by the operator and will reduce mistakes (human error).

Expected Overall Effect including Phase I and Phase II.

Project Life and Increase in Output. The Project Life is estimated at 24 years with operation of 20 years from the year of 2003 and will increase in power and heat outputs throughout the project life. The incremental outputs are calculated based on the data issued by the Energy Authority.

Operational indicators of the Project at the level of 2007 are (i) net electric energy production will increase by 15% against net production of 2000 (1542 GWh); (ii) maximum electric power demand will reach 410 MW (330 MW was the level in 2000); and (iii) utilization factor will amount to 46% when it was 40,4% in 2000 year level. The data shows a projection of respective power and heat outputs of the 4th Thermal Power Station until the year of 2006. It is assumed that the full output reached in 2003 will be kept constant until the end of the project life. The annual power output without the Project is also technically estimated on a condition that the present facility will be properly maintained. It is also assumed that the capacity of turbines and generators will be adequate to meet the estimated increase of the power and heat output.

34

Increase in Operation and Maintenance Cost. The new facilities introduced under the Project will lead to additional operation and maintenance (O&M) costs. The cost increase will be charged from the year of 2003 and increase with time. The initial incremental cost is estimated at 1,193,500 thousand Tug.in 2003 and will be kept constant at 1,912,000 thousand tug rug, through the year of 2011. It is also assumed that the incremental cost of 2,387,000 thousand Tug. will start in 2012 and continue throughout the project life. Increase in efficiency of boilers and reduction of auxiliary electrical power. The new power system is expected to result in an efficiency increase of the boilers and also a reduction of auxiliary electrical power. Both factors can be converted into reduced coal consumption. The estimated amount of reduction coal consumption is 180,830ton/year and 50,400 ton/year respectively. If only 70% of volume of coal reduction is achieved and applying the current average coal price at 6,400Tug. /ton, the calculated savings are 810,112 thousand Tug. /year and 228,352 thousand Tug. /year. Effect on Environmental Conditions. About 3’500 thousand tons and 2’000 thousand tons of coal have been consumed in Ulaanbaatar city and by the 4th Thermal Power Station a year respectively (the relevant CO2 emissions are 2’791 thousand tons and 1’595 thousand tons per year).

As a result of the Japanese loan project, the coal consumption of the TES#4 will be reduced by 231,230 tons a year (184’000 tons of CO2 emissions). These remarkable reductions of emitted CO2 will contribute to the reduction of global warming, as well as the health protection of people living in Ulaanbaatar city.

1.5 Environmental Protection

Environmental Status. Mongolia is a large and sparsely populated country with a harsh climate and about two and half million people inhabitants within an area of 1.57 million square kilometres. The climate of Mongolia is dry and has extremely cold temperatures in winter. Annual average precipitation in Ulaanbaatar (capital city of Mongolia) is only 293mm. In the southern areas surrounded by the semiarid steppes and Gobi desert and in the eastern area also surrounded by the semiarid steppes, 70 to 80 percent of total precipitation is concentrated in three months (from late June to mid September).

The country is situated at high northern latitude and at a high elevation (average 1,580 meters). The average annual temperature is very low (in Ulaanbaatar, the average annual temperature is - 0.6°C). As the country is also isolated from the sea, the temperature during the year fluctuates widely (- 39°C to +38°C in Ulaanbaatar). The winter is long, cold and dry with low wind and frequent temperature inversions. These climate conditions have a direct influence on environmental conditions in Mongolia. The climate in Ulaanbaatar city is shown on Table 1.5.1.

Table 1.5.1 Temperature, Precipitation and Humidity in Ulaanbaatar City

Parameter 1 2 3 4 5 6 7 8 9 10 11 12 Ave

Temp (°C) -20.9 -17.1 -8.0 1.5 9.8 14.3 16.7 15.1 8.8 1.1 -11.6 -17.3 -0.6

Precipitation (mm)

2.4 2.4 6.6 5.8 14.6 55.6 64.0 92.7 26.9 12 5.4 4.8 *293

Humidity (%)

81 77 66 52 52 58 65 70 65 64 72 81 67

(Data: 1986~ 990) Meteorological research 1991.7 * - shows total precipitation in a year.

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As Ulaanbaatar city (capital city of Mongolia) is located in a basin surrounded by

mountains of height of 1652 to 1949 meters above sea level, the air pollution induced by the temperature inversion is greater than other cities of similar nature in the world. The temperature inversions occur during the months of October to April. The temperature inversion occurs at the level of 650-920 meters above ground level. Sand storms intermittently occur (about 26 times a year). Air pollution also results from the uncontrolled emissions from industries using coal, from heating only boiler stations, and emissions from households burning coal for room heating.

The wind roses in Ulaanbaatar show the wind direction from west to North West and the wind velocity is 1 to 2 meters per second. The smoke and flue gas in Ulaanbaatar city have been mainly emitted from stacks of coal-fired thermal power station and Mongolian traditional houses (called "gher"). Forty-eight (48) percent of the population of Ulaanbaatar city live in "gher" using stoves fuelled with coal/and/or wood both for house-warming and cooking purposes. From these fuel sources toxic substances such as carbon monoxide are emitted into the atmosphere.

Environmental Pollution. In Ulaanbaatar city, there are four air-quality monitoring stations by which the daily concentration of NO2, SO2, CO and dust are measured under the Japanese loan project. From these measurements it is noted that the emission of NO2 and dust often exceed the permissible level.

TES#4 has a stack with a height of 250 m, inner diameter-8 m, and base diameter-35m. There is an electro-static precipitator (ESP) of EGA2-58-12-6-4 type, which is installed for removal of fly ash in flue gas and has an efficiency of ash removal of 98-99%, voltage for electrode 40-5-50 kV and allowable flue gas temperature of 150°C. The ESP is switched on and off by remote control with an automatic control system as part of the rehabilitation activities under the Japanese Grant Aid. Before this rehabilitation the ESP experienced problems with the ash disposal system and problems with the motor-gear for the vibration system. Sometimes the capability of ash removal was reduced by 25-30% and was stopped for over 2200 hours for maintenance. Since 1992, maintenance hours have reduced down to 1200 hours and the effectiveness has increased to 98% as a result of this grant aid rehabilitation project.

Operating effectiveness of the electrostatic precipitator (ESP can be evaluated using the air quality monitoring station data for, NO2, SO2 and O2 emission levels (Tables 1.5.2-1.5.4).

Table 1.5.2 - Method of Analysis

Item

Method

SO2 Controlled potential electrolysis method

Model NOS-700, (Best instrument Co., Ltd) NOx Controlled potential electrolysis method

Model NOS-700, (Best instrument Co., Ltd) O2 Zirconia type oxygen method

Model NOS-700, (Best instrument Co., Ltd)

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Table 1.5.3 - Dust Data (Annual)

Date 1993 1994 1995 1996 1997 1998

EP inlet 7.51

13.83 13.71 0.965 7.71 13.26:

EP outlet g/m3N) 0.66 0.33 0.45 0.004 1.08 0.54 efficiency (%)

91 98 97 100 86 96

C02 % 12.6 13.8 14.6 11.5 14.5 13.2 O2 % 6.3 5.0 4.3 5.4 5.1 6.6 N2°/o 81.1 81.2 81.1 83.1 80.4 80.2 H20°/o 8.3 8.4 6.4 7.7 - 4.5

Recorded by: Power Station

Table 1.5.4 - SO2, NO2, and O2 Data Point: EP outlet Unit #1 #2 #6 #3 #5 date 1998/2/24 1998/10/8 NOx (ppm) 190 296 274 178 320 S02 (ppm) 247 480 540 467 599 O2 (%) 15.0 11.2 8.8 9.6 11.4

Point: EP inlet Unit #3 date 1998/10/26 NOx (ppm) 60 101 92 78 SO2 (ppm) 375 507 496 482 O2 (%) 11.8 8.2 6.6 8.5

Point: EP outlet Unit #3 #5 #6 date 1998/10/26 NOx (ppm) 141 148 120 110 252 247 242 225 208 SO2 (ppm) 474 440 398 374 330 324 317 236 216 O2 (%) 5.5 5.6 8.7 9.3 11.7 11.8 12.0 13.4 13.8

Recorded by: Power Station All the wastewater from the power station is collected at the Slurry pit. The wastewater is pumped to the ash disposal pond, in the amount of about 2000t/h. This pond is situated about 4 km away from the power station and has a circumference is about 2 km. The ash is settled and the superficial water is sent back from the ash disposal pond to the power station for recycling without being discharged outside. This system has no treatment equipment. Figure 1.5.1 shows the wastewater flow.

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Figure 1.5.1 - Ash Disposal Flow Diagram with Water

Noise from the power station is a very low level at the area surrounding the power station However, sometimes a high sound level is created when the electric valves release steam resulting from bringing a boiler into parallel with the other boilers. This sound level is 88dB (A) at about 60m from valves. Figure 1.5.2 and Table 1.5.5 show measurements of sound level at power station and Figure 1.5.3 and Table 1.5.6 shows measurements of the sound level outside the power station.

Figure 1.5.2 - Measuring Sound Level at Power Station

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Table 1.5.5 - Sound Level Measurement (Inside of Power Station)

Point

Sound level

Point

Sound level

Point

Sound level

Bldg side 57 Stack side

70 1 #3 IDF 86

Cooling tower 84 ditto 71 2 #3 IDF 91

Turbine side 66 ditto 66 3 #3 IDF 88

ditto 73 ditto 64 4 #3 IDF 86

ditto 76 ditto 62 5 #3 FDF 84

ditto 71 ditto 61 6 #3 FDF 91

ditto 63 7 #3 FDF 94

ditto 66 8 #3 FDF 92

Cooling tower 77 9 #3 Mill 90

Stack side 66 10 #3 Mill 102

ditto 69 11 #3 Mill 100

Figure 1.5.3 Sound Level Measurement Points (Outside of Power Station) Table 1.5.6 - Sound Level Table 1.5.7 - Noise Standard Measurement (Outside of Power Station)

Point Sound level Place Time dB(A)

Road 46 23:00-7:00 45 Gate 51

Resort 7:00-23:00 35

2 km from Gate 45 23:00-7:00 55 Road 48

Resident 7:00-23:00 45

Road 44 Clinic - 55 Gate 45 23:00-7:00 60 Road 46

Hotel 7:00-23:00 50

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Table 1.5.8 - Present Status of Environmental Equipment

Equipment

Existing conditions with recent rehabilitation. Electric Precipitator

Wear and tear of electrode, damage of hammering equipment. It is necessary to check the function of EP by instrument. Replacement is not required.

Water Treatment System

No specific trouble. Required regular inspection and maintenance. Replacement is not required.

Waste Water Treatment System

It is observed that there is contamination of ground water in the ash disposal ponds. In the long term there is a need for improvements of the wastewater treatment.

Measurement Instruments

Dust, SO2, NOx, noise and water quality measurements are taken using a portable instrument from the plant laboratory.

2.0 Energy Efficiency Improvement Options

As discussed in Chapter 1, considerable improvements in the continuous and reliable operation of the TES#4 were achieved in 1995-1999. The ongoing Phase II of the Japanese loan project is designated to maintain and increase the results of its Phase I.

Generally, the efficiency improvements in the power plants pursue a triple target (i) reduction of the specific fuel consumption and thus of the generation costs; (ii) contribution to the indirect emission reduction; and (iii) preservation of coal resources, not only as a precautionary measure, but also having in mind the economic consequence that natural resources will become scarce and more expensive due to the consumption in the long run. For meeting the economic goals it is necessary to reduce the investment costs and increase the efficiency of power plants at the same time. In this connection, the energy efficiency options for the power plants are more promising than the technological changes.

Table 2.1 summarizes some of the potential actions that are commonly taken to improve plant efficiencies in western countries [Review of Potential Efficiency Improvements at Coal-Fired Power Plants7]. This data are based on the higher moisture "brown coal" or lignite similar to Mongolian coals. These actions include those that would help restore the plant to its design conditions, change existing operational settings, or install retrofit improvements.

In power plant operations, two main goals are set forth from an integrated environmental and engineering perspective: to burn the fuel cleanly and to exploit as much as possible of the fuel’s energy value. With regard to energy exploitation, there are inherent inefficiencies in the production of electric power. Efficiency in coal fired power generation is measured by the portion of the energy in the fuel that is converted into electricity and heat at the power plant for delivery to the customer. Factors involved in overall efficiency include: combustion, thermal transfer, and generator, transmission, and end-use (consumer) efficiencies.

7 The Clean Air Markets Division, U.S. Environmental Protection Agency contracted Perrin Quarles Associates, Inc., to perform a review of readily available data on potential and actual efficiency improvements at coal-fired utilities.

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Table 2.1 - Measures that may improve the Efficiency of Coal-Fired Power Plants

ACTION8 EFFICIENCY IMPROVEMENTS (%)

Restore Plant to Design Conditions Minimize boiler tramp air 0,42 Reinstate any feed-heaters out of service 0,46-1,97 Refurbish feed-heaters 0,84 Reduce steam leaks 1,1 Reduce turbine gland leakage 0,84 Change to Operational Settings Lower excess air operation 1,22 Improved combustion control 0,84 Retrofit Improvements Extra air-heater surface area in the boiler 2,1 Install new high efficiency turbine blades 0,98 Install VSD on motors 1,97 Install on-line condenser cleaning system 0,84 Install new cooling tower film pack 1,97 Install intermittent energization to ESPs 0,32

The measure of ‘coal drying with heat recovery’ is a capital-intensive process and the

technology has not been used on a major utility boiler. Hence it should be viewed as being not commercially nor technically proven at this stage. Because of the different plant configurations and the variable conditions of the each station, not every item can be implemented at each station.

There are a number of items, which will 'overlap' in their effect such that the efficiency gains are not directly additive. For example extra air-heater surface areas, lower excess air, minimisation of tramp air and re-installation of feed heaters will interact such that the overall improvement will be significantly less than the sum of the individual items. For each station detailed calculations would need to be undertaken to determine the combined effect of inter-dependant initiatives.

For a number of the initiatives the gain in efficiency stated would appear to be optimistic. The improvement of 1.97% stated for the installation of variable speed drives needs to be considered in relation to the overall auxiliary power usage, approximately 8%, and the extent of variable speed drives already installed. The motors without variable speed drives amount to less than 4% of generated output and thus a saving of approximately 50%. These savings levels would thus seem to be unattainable at TES#4. Variable speed drives usually show an efficiency improvement only where the station operates for a proportion of time at lower loads. Because of the economics, brown coal fired stations do not normally operate for long periods at low loads.

Another efficiency improvement measure where the nominated gain would appear to be optimistic is for the improvement of the cooling tower performance by the inclusion of a film pack. A potential improvement of 1.97% has been stated. Based on a theoretical thermodynamic calculation in order to achieve this improvement a reduction in condenser pressure of 3.5 kPa would be required which in turn would necessitate an 8oC reduction in

8 They are options such as various equipment control upgrades such as distributed control systems, precipitators and turbine controls; metering upgrades; boiler chemical cleaning upgrading; feed water heater improvements; reduced condenser air in-leakage and reduced thermal losses.

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cooling water temperature. A film pack is capable of reducing the water temperature by only some 3oC. The foregoing analysis is based on theoretical considerations. In practice, because of the restriction of the exhaust flow area, the actual gain in efficiency due to an improvement in condenser pressure will be below the theoretical predictions.

Using the assumptions for gross electricity and heat generation levels, the total fuel heat rate, gross electrical efficiency and station efficiency of the TES#4 are 2150 GWh, 3040 GWh, 8592 GWh, 25,2% and 60.4%, respectively, at the present level, the avoided CO2 emission costs for the more viable options have been estimated (see Table 2.1B).

Table 2.1B – Avoided CO2 Emissions from Energy Efficiency Options (UB TES#4 case)

Action

Incr

ease

d ef

ficie

ncy

%

Red

uctio

n of

Fu

el h

eat r

ate

GW

h/yr

Avo

ided

Coa

l C

onsu

mpt

ion

103 to

ns/y

r

CO

2 em

issi

on

redu

ctio

n 10

3 tons

/yr

CO

2 em

issi

on

redu

ctio

n co

st

103 U

S$/y

r

1 Cooling tower film pack9 62,36 269,34 76.99 123,18 615.9

2 Coal drying with heat recovery 64,9 595,06 170,12 272,19 1360,9

3 On-line condenser cleaning system 61,24 117,13 33,47 53,54 267,74

4 High efficiency turbine blades 61,38 136,46 38,99 62,39 311,95

5 Extra air heater surface in the boiler + add. soot blowers

62,5 287,98 82,32 131,7 658,54

In order to advance the practical options for efficiency improvement a soundly based

engineering study with costs would need to be undertaken for TES#4

With regard to clean coal burning, the traditional focus has been on particulate, SO2, and NOx emissions. Table 2-2 provides a layout of clean coal technologies that might fall under the pollution prevention umbrella, depending on either the parallel implementation possibilities of options or overall impact of a particular option. Options under the retrofit category may be applied to existing power plants, whereas options under the new/re-powering category would generally apply to new or substantially modified facilities.

Table 2-2 Selected Clean Coal Technologies

Pre-combustion Combustion Retrofit New/Repowered Physical Cleaning Fine Grinding Advanced Froth Flotation Heavy Media Cyclones Micro bubble Flotation Advanced Drying Physiochemical Molten Caustic Leaching Microbial Bioleaching

Low NOx Burning Multistage Burning

Gas Re-burning Fluidized-Bed Combustion

Fuel Changes Fluidized-Bed Combustion10

9 The most efficient heat transfer method for counter-flow cooling towers is accomplished via cross-corrugated film-type media or fill. This fill is thermally formed from rigid polyvinyl chloride (PVC), which resists decay and fungus or biological attack. 10 Recent technological developments have led to the capability of powering "combined-cycle" generators. Two new technologies – Pressurized Fluid Bed Combustion and Integrated Gasification Combined Cycle (IGCC) –

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OPTION-1 Coal Cleaning

Most naturally occurring low-sulfur coals in Mongolia, including the coal used in TES#4, have distinct handling and combustion characteristics and, therefore, chemical and biological cleaning11 is not required.

Low rank coals in Mongolia have relatively high ash and moisture content. Due to their high moisture content, coals of the Baganuur and Shivee-Ovoo have a low heating value.

For Mongolia, coal cleaning has not been performed either at the mines or at the power plants up to the Baganuur and Shivee-Ovoo Coal Mine Development Project. Coal cleaning is very important to reduce ash and moisture content in order to increase the coal’s heating value. Within the above project, implemented during 1997-2003 with the help of JBIC of Japan, the dewatering systems were constructed and environmental monitoring and coal analyses equipment was supplied to the mines of Baganuur and Shivee-Ovoo, from which the TES#4 receives coal. They are in fully normal operation to date.

Coal cleaning also provides economic benefits from reduction in shipping costs. Cleaning requirements with regard to size, ash, and moisture content has evolved from consideration of engineering and operating efficiency concerns.

Presently, a permit system for sources of pollutants from the power plants is not in force in Mongolia and the power plants are buying the relevant coal from the certain mines with designated coal, without considering moisture and ash content.

If there was implementation of coal cleaning technology in the Baganuur and Shivee-Ovoo coal mines, from which the TES#4 takes its coal, or in the premises of the TES#4, the calorific values would increase and the ash contents would decrease substantially, and the station overall efficiency would increase by 2-5 % depending on the applied technology. On average, if coal cleaning technology was applied in the TES#4 it would reduce coal consumption by 134.4 thousand tons of coal per year, which would equal to a CO2 emission reduction value of 1.07 million US$ if CDM credits were possible with this change. OPTION 2 – Low NOx Burners

Controlling NOx by new or retrofitted low NOx burners is a viable energy efficiency and pollution prevention option. One common approach is to control the mixing and characteristics of fuel and air in the region of the furnace near the burner to slow the conversion of fuel-bound nitrogen to NOx, while still maintaining high efficiency in combustion.

This task is realized by controlling the quantity, momentum, and direction of the fuel and air streams at the throat of the burner as they are introduced into the chamber of the furnace. The formation of nitrogen oxide increases at higher temperatures and with the level of surplus oxygen present during combustion. As a result, if the available oxygen level in the critical NOx formation zone is limited, and the amount of fuel that is burned at peak temperatures is reduced, NOx emissions decrease. From the judgments in the foreign

have enabled combined cycle operations in the context of coal-fired facilities. These facilities have dramatically improved efficiencies or heat rates as compared to conventional pulverized coal-fired facilities. [Review of Potential Efficiency Improvements at Coal-Fired Power Plants, DOE, USA] 11 Coal may be cleaned, generally, by physical and chemical/biological means.

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literature, the low- NOx burners are being considered as a reasonably available control technology (RACT) for electric steam generating units. OPTION 3 - Repowering with CFB Boilers.

The challenges that the Mongolian energy industry face can be summarized as

follows: (i) Improve efficiency of coal utilization and utilise available resources of coal wastes to

reduce the deficit of coal production and improve the economics of coal power plants.

(ii) Improve reliability and maintainability of existing generating units by replacing the most worn-out coal fired boilers and extending the useful life of other boilers until they can be replaced by modern equipment.

(iii) Reduce air pollution from coal-fired power plants by adhering to stringent emissions limits for the replacement coal-fired boilers and improving the environmental performance of rehabilitated units.

One of the most important tasks regarding the increase in efficiency and reliability of the most important power plant in Mongolia is the repowering of the aging TES#4 for improved utilization of low-grade indigenous coals. No new power stations are planned until the year 2010. It is expected that TES#4 will run after 2020 and it must continue to play a vital role in supplying ample and stable electricity to meet the domestic as well as industrial power demand. Therefore, there is a repowering option, which uses a number of new plant components and integrates and utilizes the existing components to the maximum extent practical.

The CFB boiler technology provides the answer to the problems of upgrading the TES#4 for the following reasons:

• CFB boilers have a proven ability to efficiently utilize low-grade fuels, including those with high ash (up to 60%) contents, without the use of supplemental fuel within a wide load range.

• There is a potential for utilization of sludge and other coal wastes in CFB boilers by adding them to the main fuel. A technology of sludge preparation can be developed for fluidized bed combustion, which includes drying and pelletizing.

• CFB boilers provide SOx and NOx emission control meeting stringent pollution limits without the use of back-end gas scrubbing equipment. This has a special importance for Mongolia, which does not make this equipment.

• It is necessary to evaluate the economic effectiveness of rehabilitated boilers completed under the Japanese project with reliable and efficient continuous operation. In the long-term, these rehabilitated boilers should be replaced with a modern “clean coal” technology like CFB.

• While the CFB technology will be a long-term solution for upgrading of Mongolian power plants, PC-fired boilers will continue to produce most of coal-based power for years to come. Therefore, their life extension and economically justifiable improvements in combustion efficiency and emissions performance remain an important direction of the power plant upgrading effort.

• One more advantage of CFB technology is the possibility of increasing coal cleaning for its use as a fuel for PC boilers while adding the cleaning wastes to a fuel for CFB boilers. This would result in better overall utilization of coal for power generation.

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Fluidized-bed combustion12 (FBC) technology involves the combustion of coal suspended in a stream of inert particles and upward-moving air. FBC enhances the burning process so that the combustion temperature can be maintained at levels less favorable to NOx formation (760 to 870oC, about half the temperature of conventional combustion).

In addition, FBCs operate at temperatures considerably below the initial ash fusion range (1,150 to 1,550oC) for many coals. This substantially reduces the volume of fireside cleaning wastes and cleaning frequency.

Therefore, CFB technology can be successfully applied to utilize high-ash low-grade Mongolian anthracite, while minimizing emissions of air pollutants. Repowering with CFB boilers offers a long-term solution for upgrading of TES#4 and reducing their consumption of imported fuel oil.

The existing boilers in the TES#4 are of 220-tons/hr capacities and it is possible to

implement the program of CFB re-powering of 250-tons/hr capacities. We are preparing the circulation of low time CFB, which is not sensitive to coal category and not requires high control level and it is easy to operate. These CFBs should be operated at the load range of 50%-100%.

The station efficiency using CFB technology is approximately 0.4% better than the

existing solution. This program is estimated to give coal savings of 16,0 thousand tons per year (the CO2 emission reduction value could be 127 thousand US$ if CDM was applicable). Fuel flexibility will provide a useful safety margin for the future. Wet coal slurry (schlamm) waste combustion can be included for 30% of the basic design. OPTION 4 – Steam Turbine Modernization

The modernization concept for improving the performance of older steam turbines would result in an increase in efficiency to a level comparable with that of new turbines, while maintaining the main dimensions and steam parameters of the existing turbines. In the power industries in the world, there are at a range of modernization products of old steam turbines from several equipment suppliers including Siemens. The preferred solution is replacement of the components in the flow path including the inner casings with components of more advanced design for TES#4. This would offer the greatest potential for increasing turbine efficiency and output. New blading, modified seals and enlarged cross sections are the major issues.

As for new blading, the total number of stages, the thermodynamic load on each stage and the design of each stage itself would be optimized individually for the old turbines of TES#4. As described [August 12, 2002, Siemens’ steam power plant modernization business is trending upwards], this approach allows exceptionally high turbine efficiencies to be achieved. Hence, steam turbine modernization includes as a minimum replacement of the existing moving and stationary blades with new design blades, which have reduced profile and edge losses, have better surface quality and have an optimized blade height–to-width ratio.

The leakage through the radial seals can be reduced by smaller gaps and/or by a new system. For the HP steam turbine the double-strip seals are the most efficient. To

12 This technology is applied in three types of designs: atmospheric FBC, pressurized FBC, and two-stage bubbling bed designs, which technologically fit between the two aforementioned designs. Pressurized FBC shows promise in repowering and in new facility construction. This technology is expected to be commercially available between 2000 and 2005.

45

avoid major damage and immediate shutdown of the turbine in the event that the rotor comes into contact with the casing, the strips are caulked in and can be replaced during the next inspection. This design also allows for smaller gaps and tolerances.

The inlet and exhaust sections of older turbines may cause vortices and thus pressure drops. This becomes more apparent when the steam parameters are increased. Hence, widening the flow cross-section and optimizing the contour are an appropriate measure to increase efficiency.

Outfitting older steam turbines with modern flow-path technology can boost efficiency to levels comparable to those of new turbines. The flow path offers the greatest potential for increasing the output of older steam turbines. It is often more economical to replace the rotor, inner casing, and moving and stationary blades rather than install an entirely new turbine. It is also worth considering rewinding the generator/stator.

According to the estimates, given in the Table 2.1B, the new blading project would give coal savings of 39,0 thousand tons of coal per year, which equals to the CO2 emission reduction of 312,0 thousand US$ if CDM could be applied to this project. 3.0 Conclusions

(i) For Mongolia the most technically and financially viable solution in the near term is the further implementation of energy conservation programs, including energy efficiency improvements in the combined heat and power UB power plants, starting with TES#4 as the largest such plant.

(ii) From 1995, considerable improvements in the continuous and reliable operation of

TES#4 have been reached with help of international agencies and donors.

(iii) Coal cleaning technology is important for all the power plants and the heat only boilers in Mongolia.

(iv) As TES#4 is the main power plant in Mongolia and its design life will be reached in

2020, the further re-powering with Circulating Fluidized Boilers is important for economy to provide the reliable operation of the TES#4 for the years after 2020 and to minimize the total investments in the power and heat generation sub-sector of Mongolia. This option can be considered from 2010-2015 after the current TES#4 Japanese loan project lifetime extension has been fully utilised.

(v) In the near-term, the modernization of the steam turbines is the more viable option

in the terms of the present rehabilitation and upgrading projects taking place during 1995-2006.

46

References

1. Survey Report on the Rehabilitation of Ulaanbaatar Thermal Power Plant 4 (phase II), OECF,

2001<?xml:namespace prefix = o ns = "urn:schemas-microsoft-com:office:office" />

2. Progress reports of the Project of the Rehabilitation of Ulaanbaatar Thermal Power

Plant 4 (phase II), 2005-2006

3. Final Report, TA 3299-MON Capacity Building in Energy Planning, 2002;

4. Survey Reports, 1999-2000 ( in the framework of the TA 3299-MON Capacity

Building in Energy Planning);

5. Annual reports of the Ulaanbaatar Thermal Power Plant #4, 2004, 2005

6. Summary of the Activities of the Energy License holders for 2004, Energy Regulatory

Agency, <?xml:namespace prefix = st1 ns = "urn:schemas-microsoft-

com:office:smarttags" />Ulaanbaatar, 2005

MON TS Ulaanbaatar Power Plant

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