technical feasibility study and conceptual design

Technical Assistance Consultant’s Report

This report does not necessarily reflect the views of ADB or the Government concerned, and ADB and the Government cannot be held liable for its contents. (For project preparatory technical assistance: All the views expressed herein may not be incorporated into the proposed project’s design.

Project Number: 43357 October 2011

Mongolia: Ulaanbaatar Low Carbon Energy Supply Project Using a Public-Private Partnership Model (Financed by the Japan Special Fund) Feasibility Report Appendix 3: Technical Feasibility Study and Conceptual Design

Prepared by: HJI Group Corporation in Association with MonEnergy Consult Co. Ltd.

For: Ministry of Mineral Resources and Energy, Mongolia

ULAANBAATAR LOW CARBON ENERGY SUPPLY PROJECT USING PUBLIC-PRIVATE PARTNERSHIP MODEL

ADB TA No. 7502-MON

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APPENDIX 3: TECHNICAL FEASIBILITY STUDY AND CONCEPTUAL DESIGN

HJI Group In association with MonEnergy Consult Co. Ltd. May 2011

Ulaanbaatar Low Carbon Energy Supply Project

Using Public-Private Partnership Model

(Funded by the Government of Japan)

Project Number: TA No. 7502-MON

FINAL REPORT

VOLUME 2

Prepared for

The Asian Development Bank and

The Mongolian Ministry of Mineral Resources and Energy

by

H&J, Inc. in association with

MonEnergy Consult Co. Ltd.

May 2011

CONTENTS OF VOLUME 2

APPENDIX 3: TECHNICAL FEASIBILITY STUDY AND CONCEPTUAL DESIGN APPENDIX 4: ENVIRONMENTAL IMPACT ASSESSMENT REPORT

Ulaanbaatar Low Carbon Energy Supply Project Final Report Using Public-Private Partnership Model (TA No. 7502-MON) Appendix 3

Appendix 3-i

CURRENCY EQUIVALENTS

(As of 1 May 2011)

Currency Unit – Togrog (MNT) 1.00 MNT = $ 0.0008 $1.00 = 1,255 MNT

ABBREVIATIONS

ADB – Asian Development Bank CES – Central Energy System CFB – Circulating Fluidized Bed CHP – Combine Heat Power CO – Carbon Monoxide CO2 – Carbon Dioxide EIA – Environmental Impact assessment EES – Eastern Energy System EPC – Engineering, Procurement and Construction ERA – Energy Regulatory Authority ESP – Electrostatic Precipitator FGD – Flue Gas Desulphurization HOB – Heat Only Boilers HVAC – Heating, Ventilating, and Air-Conditioning IGCC – Integrated Gasification Combined Cycle JICA – Japan International Cooperation Agency MMRE – Ministry of Mineral Resources and Energy NDC – National Dispatch Center NOx – Nitrogen Oxides O&M – Operation and Maintenance PIU – Project Implementation Unit PM – Particulate Matter PPP – Public Private Partnership SO2 – Sulfur Dioxide TA – Technical Assistance UB – Ulaanbaatar WES – Western Energy System


Appendix 3-ii

WEIGHTS AND MEASURES

GW (giga watt) – 1,000,000,000 watts kVA (kilovolt-ampere) – 1,000 volt-amperes kW (kilowatt) – 1,000 watts kWh (kilowatt-hour) – 1,000 watts-hour MW (megawatt) – 1,000,000 watts MWt – megawatt thermal energy W (watt) – unit of active power Cal (Calorie) – unit of energy Gcal/hr (giga calorie/hr) – 1,000,000,000 calorie/hr ton – metric ton

NOTE

In this report, “$” refers to U.S. dollar.


Appendix 3-iii

CONTENTS

Drawings ..................................................................................................................................... iv

EXECUTIVE SUMMARY............................................................................................................... 1

I. ENERGY SUPPLY SYSTEM IN MONGOLIA ......................................................................... 3

A. Power and Heat Sources in Mongolia ...................................................................... 3

B. Energy Efficiency of Existing CHP Plants in Mongolia .............................................. 4

C. Air Pollution from Existing CHP Plants Not Controlled ............................................. 4

II. HEATING SUPPLY IN UB ...................................................................................................... 6

A. Heat Demand .......................................................................................................... 6

B. Heat Sources .......................................................................................................... 13

C. Heating System....................................................................................................... 16

D. Energy Efficiency and Performance of Existing District Heating System ................... 17

III. POWER SUPPLY IN UB ......................................................................................... 21

A. Power Plants in Mongolia ........................................................................................ 21

B. Power Supply .......................................................................................................... 24

C. Power Demand ....................................................................................................... 26

D. Connecting the CHP5 with the CES ........................................................................ 29

E. Issues ..................................................................................................................... 32

IV. FUEL SUPPLY........................................................................................................ 33

A. Coal Resource ........................................................................................................ 33

B. Coal Quality ............................................................................................................ 35

C. Coal Consumption Estimation ................................................................................. 35

D. Coal Transportation ................................................................................................. 36

V. SITE CONDITION OF THE CHP5 .......................................................................................... 38

A. General Description of the Site ................................................................................ 38

B. Hydrographic and Meteorological Condition ............................................................ 38

C. Water Resource ...................................................................................................... 42

D. Geotechnical Conditions ......................................................................................... 45

E. Conditions of the Ash Yard ...................................................................................... 47

F. Anti-disaster Ability Evaluation................................................................................. 48

VI. CONCEPTUAL DESIGN FOR THE CHP5 PLANT .................................................. 50

A. Installed Capacity and Key Indicators of CHP5 ........................................................ 50

B. The Plant Site ......................................................................................................... 52

C. Main Equipment Selection ....................................................................................... 57

D. Technical Conditions of Main Equipment ................................................................. 71

E. Thermodynamic System .......................................................................................... 77

F. Combustion System ................................................................................................ 80

G. Coal Conveying System .......................................................................................... 83

H. Ash Handling .......................................................................................................... 85


Appendix 3-iv

I. Chemical Process of CHP5 ..................................................................................... 88

J. Electric System ....................................................................................................... 91

K. Plant Control System .............................................................................................. 96

L. Civil Engineering ..................................................................................................... 107

M. Water Supply and Drainage System and Cooling Facility ......................................... 111

N. Ash Yard ................................................................................................................. 116

O. Fire Fighting System ............................................................................................... 117

P. HVAC ...................................................................................................................... 118

Q. Flue Gas Dust Removing, Desulfurization and Denitration ....................................... 119

R. Heating Network ..................................................................................................... 124

S. Institutional and Human Resources Arrangements .................................................. 136

T. Labor Safety ........................................................................................................... 137

U. Occupational Health ................................................................................................ 141

V. Analysis of Energy-Saving....................................................................................... 143

W. Project Implementation Schedule ............................................................................ 145

Drawings

1. Project Location Map

2. Master Plan of the CHP5 Site

3. Thermodynamic System Diagram

4. Main Equipment Layout in the Main Plant

5. Elevation of the Main Plant

6. District Heating System Diagram

7. Grid Connection System Diagram

8. Fly Ash Removing System

9. Bottom Ash Removing System

10. Coal Conveying System Diagram

11. Chemical Water Treatment System

12. Water Supply System Diagram


Appendix 3-1

EXECUTIVE SUMMARY

1. Due to the growing heating and electricity demands from Ulaanbaatar (UB) and aging existing heat and power generation facilities, there is an urgent need for the implementation of a new combined heat and power (CHP) plant to address the vulnerability of heat and power supply in the capital city. The Asian Development Bank (ADB) grant aided feasibility and environmental impact study supports the construction of a proposed new CHP plant in UB, known as the CHP5 plant.

2. The technical study focuses on demand forecasts, CHP plant justification, proposed plant size and technology, heat supply system analysis, site selection and surveys, access road and railway, coal analysis, master planning of the plant site, main equipment design, power supply system, thermodynamic system, combustion system, water supply system, control system, civil works, heating, ventilating, and air-conditioning (HVAC), pollution countermeasures, energy efficiency, water conservation and materials conservation measures, fire protection, labor safety, occupational health, heating network, institutional and staff arrangement, and implementation schedule.

3. The conceptual design of CHP5 consists of the following components:

Installed Capacity: Power generation equipments with total 820 MW of installed power generation capacity and 1281 MW (1101Gcal/hr) heating capacity will be built, including 5 x 150 MW steam extracting turbines and matched generators, plus (1) x 70 MW back-pressure turbines and matched generators; Five super high-pressure Circulating Fluidized Bed (CFB) boilers with reheater and one high-pressure boiler will be used for the CHP5, each with 525 ton of capacity.

Site Selection: The existing CHP3 site has been chosen as the site for the CHP5 through detailed technical, financial analysis and comparison among three scenarios, including the possible sites at Uliastai, CHP3, and Baganuur;

Implementation Schedule: In accordance with the demand forecast and site condition, the project is planned to be implemented in two phases. During phase I, 450 power generation capacity and 587 MW (504 Gcal/hr) heating capacity, including 3 x 150 MW steam extracting turbines, are scheduled to be built by 2015. During Phase II, an additional 2 x 150 MW steam extracting turbines and (1) x 70 MW back-pressure turbines will be installed, with 370 MW of power generation capacity and will reach 694 MW (597Gcal/hr) of heating capacity;

Grid Connection: 220 kV GIS and double circuit 220 kV interconnection lines to CHP4 220 kV switchgear are planned for Phase I of CHP5, and during Phase II, the 220 kV GIS will be extended adding two 220 kV outgoing lines to reinforce connection capacity to the system;

Water Sources: The existing water sources of the CHP3 will be used as industrial water for the CHP5, and city service water system will supply sanitary water for the CHP5;

Coal Sources: CHP5 power plant will consume 3.73 million ton of coal annually, of which 30% is sourced from Baganuur and 70% from Shivee-Ovoo;

Ash Pond: The ash is expected to be recycled for cement, brick and other construction material. The transition ash pond is situated 0.5 km west of the project site. It will be a dry ash pond. The height of the ash pond is 11 m; the storage capacity is 1.5 million m3;

Access Railway: Access railway for the CHP3 has been available. The railway authority will evaluate the capacity of the existing railway and provide improvements if necessary;


Appendix 3-2

Cooling System: Considering the water resource situation, technical reliability, energy efficiency and financial viability, the CHP5 will use a water cooling system. A total of three cooling towers will be constructed, two for Phase I and one for Phase II.

Thermodynamic System: For this project, the steam/water system will have the block configuration. The thermodynamic cucle of the extracting steam turbine has a seven-stages regenerative extracting steam system, equipped with two high-pressure heaters, one deaerator and four low-pressure heaters. The thermodynamic cycle of the back-pressure steam turbine has a three-stages regenerative extracting steam system, equipped with two high-pressure heaters and one deaerator.

District Heating System: Primary and secondary heat exchangers will be designed for the heat exchanging station in the district heating system. Using steam as the heat source of district heating extracted from the low pressure cylinder of the extracting steam turbine, water for district heating will be heated to 110 °C through the primary heat exchanger. From the middle pressure cylinder of the extracting steam turbine the hot water for district heating will be further heated up to 135 °C by the exhausting steam through secondary heat exchanger.

Combustion System: CFB will be used for this project. The corresponding primary, secondary, limestone transportation, and high-pressure fluidizing fans will be designed for combustion system. An Electrostatic Precipitator (ESP) will be designed for trapping fly ash. Two chimneys, each 250 m high and 5.5m in diameter will be constructed, one for Phase I and one for Phase II.

Coal Conveying System: Two sets of unloading machines, coal crushing and impurity removal equipment systems, belt conveyors and other auxiliary facilities will be installed for the CHP5 by phases. A coal yard will be constructed by phases. For Phase I, it will be of 250 m long by 160 m wide with a 300,000 ton storage capacity. For Phase II, it will expand to 500 m long by 160 m wide with a 600,000 ton storage capacity.

Ash Handling System: The bottom ash from the furnace will be removed continuously by bottom ash coolers, further cooled, then discharged to the bottom ash bin through two chain bucket conveyors operating in series. From there, trucks will transport the as to the ash disposal yard. The fly ash conveying system is designed to deal with each furnace as a unit, and utilizes a positive pressure dense-phase pneumatic ash-handling system.

Water Treatment System: The 100 ton/hr of output capacity boiler feed water system will use reverse osmoses and primary demineralization. The water softening system and deaerator will be used to treat make-up water for district heating system with 350 ton/hr of output capacity.

C&I System: The control system of the CHP5 plant shall be completely integrated and based on modern distributed control systems (DCS) that shall provide safe, reliable, and efficient operation of all units and the main station/common plant.

Staffing Plan: The CHP5 will require 648 employees, including engineers, managers, operators, and others.

Buildings and Structure: Within the main plant area, the following components will be constructed: the steam turbine house, the deaerator and coal silo house, the boiler house, the blowing and induced fans, the ESP, the chimney, the offices, the chemicals and water workshop, the industrial waste water treatment workshop, the service water pumps house, the fire protection and domestic water facility, the domestic waste water facility, the material depot, the lime treatment workshop, the coal yard, the hydrogen storage station, the oil tank farm, the mechanical workshop and the ash bunkers.


Appendix 3-3

I. ENERGY SUPPLY SYSTEM IN MONGOLIA

A. Power and Heat Sources in Mongolia

1. Three centralized power grids and two isolated systems supply electricity. The three centralized power grids are (i) Central Energy System (CES); (ii) Eastern Energy System (EES); and (iii) Western Energy System (WES). The two isolated systems are (i) Dalanzhadgad CHP plant and local grid, and (ii) Zhavhan and Gobi-Altai aimags. There are seven coal-fired power plants, two hydro power plants, diesel generators and small renewable energy generators.

2. Coal-fired power plants provide the majority of power generated in Mongolia. There are seven main coal-fired power plants in Mongolia with a total installed capacity of 856.3 MW. Three large sized power plants are located in UB. In 2009, 4.0 billion kWh of electricity was generated by thermal power plants and 11.05 million kWh of electricity was generated by hydropower plants. Moreover, 180.8 million kWh of electricity was imported from Russia and 21.2 million kWh of electricity was exported to Russia, due to the fact that the power plants of the system are based on conventional design and the capability of the load regulation during peak load is weak. Also, 2.8 billion kWh of electricity and 6.4 million Gcal of heat were distributed to final consumers.1 3. The CES, the largest energy supply system in Mongolia, consists of five CHP plants, one transmission network, four distribution networks, and supplies power to the cities of UB, Darkhan, Erdenet and the centers of 13 provinces. The total installed capacity of the CES is 814 MW. In 2009, the maximum power loading of the CES was 695 MW. The available power capacity is 615 MW. The present available heating capacity of thermal power plants in UB is 1,585 Gcal/hr, while the actual heating demand is 1,555 Gcal/hr, and the available heating capacity is almost fully utilized.

4. Three major combined heat & power plants, namely CHP2, CHP3 and CHP4 are located in UB. CHP2 is over 40 years old while CHP3 has been operating close to 40 years. It is generally agreed by experts that most parts of the heat production system are nearing the end of their life for these two plants. The expected retirement periods of CHP2 and CHP3 were 2005 and 2011, respectively.2 However, due to lack of new heating sources these two plants are still operating.

5. CHP4 is the biggest coal fired CHP plant in Mongolia with a design capacity of 580 WM. It covers 70% of total electricity demand of the CES and 64% of total heat energy demand of the district heating system of UB. The plant was built over 30 years ago and many upgrades and repairs have been done over recent years.

6. In addition to the CHPs, a lot of small heat-only boilers and domestic stoves have been used in UB for space heating and domestic hot water production. By 2008, UB population reached over one million and about 61.4% of them live in gers district. In accordance with the Market Study of Heat-only Boilers and Coal-fired Water Heaters in 2008, 89 heat only boiler (HOB) houses and 1,005 coal-fired water heaters were used for public buildings and apartments in and near gers districts. HOBs were designed to provide heating service to one or several schools and kindergartens as their central heat supplier. In addition, domestic stoves are widely used in gers. The 2008 survey found that there are about 103,971 heating stoves3.

1 Source: Energy Statistics, ERA, 2009. 2 Source: Feasibility Study on A Thermal Power Plant for Oyu Tolgoi Copper/Gold Mine Project, Japan Bank For International Cooperation, 2006, 3 Source: Heating in Poor, Peri-urban Ger Areas of Ulaanbaatar, Mongolia, the World Bank


Appendix 3-4

B. Energy Efficiency of Existing CHP Plants in Mongolia

7. The fuel utilization efficiency of CHPs, defined as net energy (electricity and heat) export compared to total fuel heat input to the boiler is in the range of 20-40% for all CHP plants. In a modern CHP scheme efficiencies of 50-80% are achievable. Reasons for the low total thermal energy utilization are: low boiler efficiencies; low steam/water cycle efficiencies; excessive self-consumption of heat and power; low condensate return; and, high-energy losses.

8. Through implementation of a series of measures for improving energy efficiency of CHPs, the energy efficiency of CHP3, CHP4 and Erdenet CHP have been improved greatly. The efficiency of CHP3 increased from 22.3% in 1995 to 38.6% in 2009. The efficiency of CHP4 was improved from 29.5 in 1995 to 40.1% in 2009. Erdenet CHP has the highest efficiency of 40.8%, but the Erdenet CHP has very small capacity and has little influence on local energy efficiency and environment improvement. However, the energy efficiency of CHP2 decreased from 28.9 in 1995 to 21.0% in 2009. Both Darkhan CHP and Dornod CHP have experienced a little efficiency improvement in last 14 years. The electrical efficiencies of the all power plants in the CES grid are given in the Figure 1.1.

Figure 1.1: Electrical Efficiencies of Power Plants in CES

Source: Energy Statistics Yearbook, ERA, Mongolia, 2009.

C. Air Pollution from Existing CHP Plants Not Controlled

9. Mongolia has developed and issued emission standards for coal-fired power plants, however emissions of SO2, NOx, CO and particulate matter (PM) from UB power plants remain problematic. UB CHP4 was equipped with an electrostatic precipitator (ESP), but emission control systems for SO2, NOx, and CO are not in place. Even more problematicly, CHP2, CHP3, only have inefficient wet dust removal. Additionally, many small coal-fired boilers and household stoves have been used for the purpose of heating and domestic use in UB. The air quality in UB is deteriorating rapidly due to lower energy efficiency of CHPs,


Appendix 3-5

boilers and stoves, and lack of efficient and adequate emission controls for coal-fired facilities and appliances. During the past few years, complaints about air pollution in the city have increased dramatically, especially during the winter months. It was reported by a World Bank report that UB is one of the most polluted capital cities in the world in the winter.4

4 World Bank, 2009, Initial Assessment of Current Situation and Effects of Abatement Measures, Air Pollution in Ulaanbaatar


Appendix 3-6

II. HEATING SUPPLY IN UB

A. Heat Demand

1. Current Heat Load and Heat Consumption

10. There are three categories of heat consumers in UB: industries, residential apartments, and institutions. The industry users consume steam and hot water for process needs, space heating, and sanitary purposes. The apartment and institution users mainly use hot water for space heating, daily life, and ventilation during winter season. There are three major heating modes in UB: district heating, HOBs, and domestic stoves.

11. In 2009, the district heating system served most of the urban areas and industries of UB with total heating load totaling 1,555 Gcal/hr. The three combined heat and power plants of CHP2, CHP3, and CHP4 provide the heating.

12. Nearly 61.4% of the UB urban population now resides in gers districts. The residents in the ger areas do not have access to the urban central heating system which was designed to serve only the city center. HOBs were installed to provide heat for the governmental agencies and business organizations in the ger districts, such as schools, kindergartens, hospitals, pharmacies, police stations, military bases, restaurants, shops, hot water showers, barber shops, etc.. During the 2007-2008 heating season, a total of 89 HOB houses with total heating capacity of 47 Gcal/hr as well as a total 1,005 coal-fired water heaters with a total heating capacity of 20-30 Gcal/hr were operational to service the heating loads required by the governmental agencies and business organizations in the six districts of UB.

13. The total heating load of UB is estimated at 1,602 Gcal/hr, which does not include the heat load of the ger districts. Almost all gers use domestic stoves for space heating. As these gers are geographically scattered, they are not easily connected to the district heating system. Therefore, the heat load of the gers will not be calculated in the heating load projection. 14. Total heat consumption of the district heating system is estimated at 3,429,344 Gcal; the detailed breakdown is shown in Table 2.1. The data indicate that households and industrial users are the two largest heat consumers, with each sharing nearly 30% of the total heat consumption. Hot water usage by households accounted for 13% of the heat consumption, while hot water usage by organizations and process purposes accounted for over 7% of the total heat consumption.

Table 2.1: Consumption by End Users in UB, 2009

Consumer Classifications Heat Consumption

Gcal %

1 Industrial users and enterprises with heat metering 1,021,527 29.8%

2 Heating for households - residential apartments 995,191 29.0%

3 Hot water use of household consumers 453,096 13.2%

4 Process hot water use 274,940 8.0%

5 Apartments with heat metering 249,655 7.3%

6 Organizations 246,077 7.2%

7 Others 188,857 5.5%

Total 3,429,344 100.0%

Source: ERA, MMRE, Mongolia


Appendix 3-7

2. Heat Load Estimations

15. The available 47 Gcal/hr heating capacity provided by HOBs is projected to be the potential heat load to be covered by the district heating system, and the CHP5 is expected to replace the heat only boilers (HOBs). Moreover, the economic development and implementation of the planned housing improvement program in UB will increase heat demand.

a. Heat Load Estimation by Energy Authority 16. The Energy Authority estimates that heat demand will increase by 242.3 Gcal/hr by 2012, and almost 1,000 Gcal/hr by 2020. Figure 2.1 illustrates the increasing trend of the heat demand.

Figure 2.1: Heat Load Estimates by Energy Authority

Source: Energy Authority, MMRE, Mongolia

17. It is expected that the heat load will reach 2,176.3 Gcal/hr by 2015. The available heating capacity in UB is 1,585 Gcal/hr, leaves a supply gap of 591 Gcal/hr. In 2020, the gap will increase to 970 Gcal/hr. To bridge the gap, new heat source facilities, such as CHP plants and HOBs, will need to be constructed.

b. Heat Load Estimation by JICA 18. The heat load estimation of UB was completed by JICA team in the Study on City Master Plan and Urban Development of UB (the Study). Figure 2.2 presents the estimation results. The Study estimated that the heat load deficit will reach 287 Gcal/hr by 2010, 744 Gcal/hr by 2015, and 1178 Gcal/hr by 2020. However the total heat capacity surplus in 2007 was 246.3 Gcal/hr, leaving a 30 Gcal/hr deficit in 2010. The deficits in 2015 will be 496 Gcal/hr, 932 Gcal/hr by 2020, and 1,733 Gcal/hr by 2030.

1585

970.5 995.1 1073.2 1190.2 1301.21555

1797.3

2176.3

2555

500

1000

1500

2000

2500

3000

2001 2002 2004 2006 2008 2010 2012 2015 2020

Available Heat Capacity (Gcal/h)Estimated Heat Demand (Gcal/h)


Appendix 3-8

Figure 2.2: Heat Load Estimation by JICA Team

Source: Study on City Master Plan and Urban Development of UB City

19. In summary, the heat load estimation made by JICA team is close to those made by the Energy Authority. On average, both estimations suggest an increase of an additional heat capacity of over 450 Gcal/hr by 2015 and over 900 Gcal/hr by 2020.

c. Heat Load Estimation by TA Team 20. The population of the city of UB (almost 40% of the national population) is approximately 1.07 million people or 255,000 households, of which, 38.6% live in an apartment and 61.4% live in a ger-house. Currently, only apartments are connected to the district heating system. The Mongolian Government initiated the “40,000 Family Apartments” program to construct apartment facilities for 114,100 families in 13 different locations. It was expected that an additional 206007 families will become the potential heat consumers connected to the district heating system. Table 2.2 below lists details of the heat demand by these potential heat users by 2030.

Table 2.2: Heat Demand Forecast By 2030

№ Consumer Name Number of

Households Population Heat Load, Gcal/hr

By 2030

1 Buyant-Uhaa 12,500 52,500 93.8

2 Bayangol 18,000 75,600 135.0

3 City new center 12,500 52,500 93.8

4 Sunshine 10,000 42,000 75.0

5 Yarmag-1 5,000 21,000 37.5

6 Future sub district 13,000 54,600 97.5

7 Japan town 4,000 16,800 30.0

8 Marshal town 2,195 9,877.5 16.5

9 XIV sub district 12,000 50,400 90.0

10 East Selbe sub district 4,500 18,900 33.8

11 VII sub district 10,000 42,000 75.0

12 TV center surroundings sub district 4,200 17,640 31.5

246.3 287

744

1178

1590

1979

0200400600800

1000120014001600180020002200

2007 2010 2015 2020 2025 2030

Reserved Heating Capacity (Gcal/h)

Additional Heat Demand (Gcal/h)


Appendix 3-9

№ Consumer Name Number of

Households Population Heat Load, Gcal/hr

By 2030

13 Military town 5,930 24,906 44.5

14 Wall material surroundings 11,600 48,720 87.0

15 Gandan temple sub district 582 3,900 4.4

16 Hill 1000 sub district 6,100 25,620 45.8

17 Golden park 1,500 6,300 11.3

18 Rainbow apartment sub district 2,000 8,400 15.0

19 Chingis avenue, XIX sub district 4,151 18,679.5 31.1

20 Middle River around sub district 1,000 4,200 7.5

21 Rotation-32 10,000 42,000 75.0

22 Olympic town 2,000 8,400 15.0

23 Onor sub district part-B 2,640 11,088 19.8

24 Moscow sub district part-II 3,150 13,230 23.6

25 Dar-Eh private apartments II stage 256 1,075.2 1.9

26 Dar-Eh sub district private apartments 4,044 16,984.8 30.3

27 Mamba temple 2,100 8,820 15.8

28 Yellow stone 720 3,024 5.4

29 US-15 2,310 9,702 17.3

30 Uliastai 5,600 23,520 42.0

31 Altan-Ulgii surroundings 9,000 36,000 67.5

32 Amgalan 16,000 71,960 120.0

33 III-IV sub district II stage 1,979 8,905.5 14.8

34 Modern Mongolia sub district 700 3,150 5.3

35 West-South industrial area 3,000 13,500 22.5

36 Weave factory around sub district 1,750 7,350 13.1

Total: 206,007 873,252.5 1,545.1

Source: Government of UB City

21. In addition, the municipal government of UB has forecasted that by 2015 the additional heating demand will reach 343 Gcal/hr. Table 2.3 below lists details of the heat demand by these potential heat users by 2015.


Appendix 3-10

Table 2.3: Heat Demand Projected by City Government By 2015

No Sub-district and Consumers Heat Load, Gcal/hr

2015

1 Buyant-Uhaa 26.6

2 Bayangol 30.0

3 City new center 4.2

4 Sun shine 18.8

5 Yarmag-1 26.3

6 Future sub district 11.3

7 Japan town 11.3

8 Marshal town 7.5

9 XIV sub district 37.5

10 East Selbe sub district 23.6

11 VII sub district 49.5

12 TV center around sub district 15.0

13 Military town 7.5

14 Wall material around 7.5

15 Gandan temple sub district 2.3

16 Hill 1000 sub district 7.5

17 Golden park 22.5

18 Rainbow apartment sub district 15.0

19 Chingis avenue, XIX sub district 11.3

20 Middle River around sub district 7.5

Total 343


22. In addition, heating company data from 2007-2009 indicated that a great number of apartments, with a total construction area of 1,959,812 m2 and a total heat load of 223 Gcal/hr, were connected to the district heating system, which may increase at an annual rate of 8% due to the booming housing development and commercial construction activities. However, JICA’s Study projected a declining trend in the increasing population rate in central UB, estimated at a 4.0% by 2010 and 2.0% by 2030. This indicates that the heat demand will dramatically increase during 2010-2020, comparing to 2020-2030. In accordance with the implementation schedule of Family Apartments Program, it is expected that the additional heat load will reach 991 Gcal/hr by 2020 as shown in Table 2.4.


Appendix 3-11

Table 2.4: Heat Demand Projected by City Government By 2020

№ Consumer name Number of house holds Population Heat load (Gcal/hr)

By 2020

1 Buyant-Uhaa 12,500 52,500 93.8

2 Bayangol 18,000 75,600 135.0

3 Sity new center 12,500 52,500 93.8

4 Yarmag-1 5,000 21,000 37.5

5 VII sub district 10,000 42,000 75.0

6 TV center around sub district 4,200 17,640 31.5

7 Wall material around 11,600 48,720 87.0

8 Gandan temple sub district 582 3,900 4.4

9 Hill 1000 sub district 6,100 25,620 45.8

10 Middle River around sub district 1,000 4,200 7.5

11 Sun shine 10,000 42,000 75.0

12 Future sub district 13,000 54,600 97.5

13 XIV sub district 12,000 50,400 90.0

14 Rainbow apartment sub district 2,000 8,400 15.0

15 Olympic town 2,000 8,400 15.0

16 Weave factory around sub district 1,750 7,350 13.1

17 Japan town 4,000 16,800 30.0

18 Military town 5,930 24,906 44.5

Total: 132,162.0 556,536.0 991.2


23. Considering the inefficient, aged, and deteriorated equipment and systems, it is suggested that the CHP3 plant be decommissioned much sooner, especially its low-pressure system. The CHP5 plant is recommended to be constructed in two phases: Phase I to be completed by 2015 and Phase II by 2020. It is justifiable to phase out CHP2 and CHP3 upon construction of CHP5. It is expected that the CHP2 will be improved through other project efforts and it will continue to provide heat service to its existing customers. However, the low- pressure system of CHP3 should be decommissioned before 2015 to provide land space for the 2nd phase of the CHP5 Project. As a result, the heat load of 110 Gcal/hr currently accommodated by the low pressure system will be taken care of by CHP5 by 2015. Arithmetically, the total heating capacity equals 343 Gcal/hr plus 110 Gcal/hr, totaling 453 Gcal/hr. Due to the fact that the high-pressure system of CHP3 has been rehabilitated in recent years, some facilities still can normally operate for a few years. Therefore, it is decided that the high-pressure (HP) system of the CHP3 will not be decommissioned before 2020. Table 2.5 provides detailed heat demand estimations during 2015, 2020 and 2030.


Appendix 3-12

Table 2.5: Heat Demand Estimations

Retirement Schedule Assuming Retirement of CHP3 by 2030

Year 2015 2020 2030

Unit Gcal/hr Gcal/hr Gcal/hr

Retirement of Heat Capacity 110 110 485

Additional Heat Demand 343 991 1,545

Total Heat Capacity 453 1,101 2,030

Source: TA Team estimates.

24. International best practices suggest that a CHP plant be designed according to a well-justified capacity. It is not justifiable to design the CHP5 with the heating capacity of 2,030 Gcal/hr for the year 2030 because it would be difficult to manage the associated heat transmission and distribution system. Possible fluctuations in the projected heat demands by 2030 are likely and could result in financial risks or unexpected outcomes for the CHP5. Therefore it is preferable that the CHP5 be designed with a heating capacity for the year 2020, building the CHP5 in two phases. The 2015 target set for Phase I and the 2020 target set for Phase II are practicable and reachable. The implementation arrangement for the CHP5 can be made in a more flexible approach to satisfy the specific project needs. The heating capacity of the CHP5 is therefore designed to be 453 Gcal/hr by 2015 and 1,101 Gcal/hr by 2020.

3. Heat Demand Curves

25. Based on this heating demand analysis, the heat demand vs. time curve is shown in Figure 2.3 below.

Figure 2.3: Heat Demand Curve against Time

Source: TA Team


Appendix 3-13

B. Heat Sources

1. CHPs

26. The heat sources of the district heating system in UB are from CHP2, CHP3, and CHP4. These power plants were constructed using Chinese and former Soviet Union equipment and technology, and have been operating for 25-47 years. Together, there are 25 boilers with different capacities and working parameters in the existing CHPs, with a total thermal capacity of installed boilers of 5,570 ton/hr. Currently, the available thermal capacity for heating is 1,585 Gcal/hr. Detailed heating capacities and heat loads are described in Table 2.6.

Table 2.6: Heating Capacities and Heat Loads

№ Source Present Available Heat

Source Gcal/hr

Load of Total Connected Consumers

Gcal/hr

Remaining Capacity Gcal/hr

1 CHP No.2 55 54 1

2 CHP No.3 485 485 0

3 CHP No.4 1,045 1,016 29

Total 1,585 1,555 30

Source: Energy Authority, MMRE, Mongolia

27. CHP2 was put into operation in 1961. At first this power plant was equipped with two medium pressure stoker boilers, each with a thermal capacity of 35 ton/hr. In 1969, CHP2 was expanded with two additional pulverized coal fired medium pressure boilers with total thermal capacity of 150 ton/hr. CHP2 provides both hot water for space heating and steam for industry usage. The total thermal capacity is 55 Gcal/hr. Due to aged and deteriorated equipment and system, the efficiency of CHP2 has dropped from 28.9% in 1995 to 21.0% in 2009. The coal equivalent consumption rate for heat generation of CHP2 is 200.8 kg/Gcal, much higher than the average international level of 160 kg/Gcal. In addition, there are no efficient emission controls on the power plant resulting in serious air pollution. Although CHP2 was expected to be decommissioned in 2005, it has had to continue working because no newly built heat and power sources can replace it. Therefore, it is urgent that this power plant be demolished as soon as possible to mitigate the environment pollution and improve energy efficiency.

28. CHP3 has both high and low pressure systems. Six low pressure boilers with 450 ton/hr of total thermal capacity were installed in the low pressure system, and seven high-pressure boilers with 1,540 ton/hr of total thermal capacity were used in the high-pressure system. The construction of the low pressure system started in 1966 and began to provide heat and electricity to the city in 1973. Construction of the high-pressure system started in 1976 and was fully completed in 1981. At present, CHP3 covers 32%of the heat demand of district heating system in UB. It also supplies process steam to more than 70 industrial customers. Through a series of improvement measures, the


Appendix 3-14

efficiency of CHP3 increased from 22.3% in 1995 to 38.6% in 2009. The coal equivalent consumption rate for heat generation is 182.9 kg/Gcal, still higher than the average international level of 160 kg/Gcal. Like CHP2, CHP3 was also not equipped with efficient emission control devices. The low pressure system of CHP3 is the least efficient of the group and should be closed.

29. CHP4 is the biggest coal-fired CHP plant in Mongolia. Eight boilers with a total installed thermal capacity of 3,390 ton/hr make up the CHP4. The available heating capacity of CHP4 is 1,045 Gcal/hr. It covers 64.3% of the total heat demand of district heating system in UB. With the implementation of a series of improvement projects for CHP4, the efficiency of CHP4 increased from 29.5% in 2005 to 40.1% in 2009. The coal equivalent consumption rate for heat generation of the CHP4 is 173.6 kg/Gcal, close to the average international level of 160 kg/Gcal. An ESP has been installed in CHP4, but there are no emission control systems for SO2 and NOx.

2. HOBs

30. In addition to the CHPs, numerous small heat-only boilers and water-heaters are in use in UB for space heating and domestic hot water production. In accordance with the 2008 “Market Study of Heat-only Boilers and Coal-fired Water Heaters”, 89 heat-only boiler houses have 24 types of boilers, numbering 166 and are in operation with 140 Gcal/hr of total thermal capacity. HOBs have the capacity ranging from 250 kW to 1,000 kW and were designed to provide heating service to one or several schools and kindergartens as their central heat supplier. During the 2007-2008 heating period, the total heat load for the 89 HOB houses was 47.35 Gkal/h, total energy consumption was 123,212 Gcal, and a total 64,605 tons of coal were consumed. The detailed information of HOBs is seen in the Table 2.7.

Table 2.7: HOB Data

Districts

Heating Coal

Load Gcal/hr

Annual Consumption

Gcal Consumption

t/y Cost

Million MNT

Han-Uul 16.5 42,797.0 23,329.0 787.0

Bayanzurh 17.1 44,530.0 23,452.0 606.5

Songinohairhan 5.8 15,158.0 6,587.0 407.2

Suhbaatar 2.8 7,169.0 3,415.0 180.3

Chingeltei 4.9 12,628.0 9,390.0 543.2

Bayangol 0.4 930.0 470.0 21.1

Total 47.4 123,212.0 66,644.0 2,545.3

Source: Market Study of Heat-only Boilers and Coal-fired Water Heaters, MONET

31. In the 89 boiler houses there are 166 boilers. Of those 166 boilers there are 24 different types of boilers. There are a total of 166 boilers in operation at 89 boiler houses. Of those 166 boilers, there are 24 different types or designs. Of the 89 boiler houses, 39.8% of them are in Bayanzurkh district, 22.3% in Khan-Uul district, 16.9% in Songinokhairkhan district, 13.2% in Chingeltei district, 6.6% in Sukhbaatar district and 1.2% are in Bayangol district. There are two categories of owners of the HOBs: public servant organizations such as


Appendix 3-15

schools, kindergartens and hospitals; and, companies who acquired the HOBs during privatization that used to be under the supervision of the Municipal Boiler Usage Administration before 2006. Customers pay the companies to provide heating services.

32. These HOBs were mainly manufactured in Mongolia, Hungary, Czech Republic, and China. Usually one to two and occasionally three to four boilers are installed in one boiler house. The energy efficiency of these boilers is quite low, averaging between 50% and 60%. Most of these boilers are manually operated, and the unskilled operators and poor maintenance contribute to the poor performance of the boiler operation. These inefficient boilers contribute to higher local air pollution as well. For example, on a daily basis during November 2008 in the Khan-Uul district the HOBs produced 3.6 tons of СО, 0.36 tons of NOx, 0.3 tons of SO2 and 2.6 tons of ash.

33. In addition, 1,005 coal-fired water heaters with total capacity of 18.6 Gcal/hr were in operation in both government and business organizations in six districts of UB city. In 2008, the total coal consumption of these water heaters reached 19,857 tons. There are various types of heaters in use in both government and business organizations. Like the HOBs, they were mainly manufactured in Mongolia, Czech Republic, China, and Belarus. Detailed information related to water heaters is shown in Table 2.8.

Table 2.8: Small Water-Heaters

Districts Heat Load Gcal/hr

Annual Coal Consumptionton/yr

Boiler Quantityset

Han-Uul 1.4 1,485 44

Bayanzurh 7.9 8,516 425

Songinohairhan 3.8 4,029 233

Suhbaatar 1.2 1,191 57

Chingeltei 2.8 3,025 165

Bayangol 1.5 1,611 81

Total 18.6 19,857 1,005

Source: Market Study of Heat-only Boilers and Coal-fired Water Heaters, MONET

3. Domestic Stoves

34. According to the study of “Heating in Poor, Urban Ger Areas of UB” financed by the World Bank5, there were about 103,971 heating stoves, of which 100,941 are used to heat the gers or house during the winter months in 2008. Another 2,120 heating stoves are used by the households to heat home businesses, kiosks, or garages. The remaining 909 stoves are owned by the households as a second stove and are not being used. Household heating in ger areas of UB is a large contributor to overall air pollution in the city. The use of coal in simple heating stoves releases high levels of PM into the air. These estimates show that ger area household heating contributes to about 45–70% of the PM2.5 concentrations as an overall annual average for the whole city. The actual impact depends on the time and the location in the city, but is generally highest in ger areas. Ger area heating systems burn continuously during the winter season and their contribution to the overall air pollution levels reaches 70% and more in the ger areas and up to 60% in the city center.

5 World Bank, Heating in Poor, Urban Ger Areas of Ulaanbaatar, Mongolia


Appendix 3-16

C. Heating System

35. Current heating systems include district heating system governed by the District Heating Company and other small heating systems using HOBs in UB. Once CHP5 is put into service, the CHP5 will be connected to the district heating system, and some of the existing HOBs heating system may be covered by the expanded district heating system. In this section, we will describe the situation of the existing heating systems and the potential to connect with the proposed CHP5.

1. System Configuration

36. The UB district heating system uses indirect method and direct method. The indirect system consists of main heat exchanging stations located in CHPs, primary heating pipeline, relay pumping stations, heat exchanging stations, secondary heating pipeline, controllers, and other auxiliary devices. The system has two closed loops, a primary loop and a secondary loop. Both loops work independently of each other without direct interference. In this system, the working pressure of the primary heating network is 1.6 MPa and the working temperatures of supply and return water of the primary heating network is 135°C and 70°C, respectively. The higher supply temperature and the temperature difference between the supply and the return will allow a smaller transmission pipe size, thereby reducing the investment cost and heat loss in the heat transmission system. Direct system employs injector to mix return water and feed water to obtain desirable feed water temperature for end-user. The working temperatures of supply and return water of the secondary heating network is 90°C and 65°C respectively. Heating coverage of the existing CHPs in UB is presented in Figure 2.4.

Figure 2.4: Heating Coverage of Existing CHPs

Source: District Heating Company of UB

Note: Other than areas circled by the two ellipses, the remaining areas are covered by CHP4.

37. The existing CHP2 and CHP4 are located on the west edge of the urban area, and CHP3 is located in the south-central part of the urban area. CHP2 covers the North-West urban area as circled by the small ellipse in Figure 2.4, CHP3 covers the central urban area as circled by the big ellipse in Figure 2.4, and the remaining network is connected with CHP4. The spatial layout of the existing CHPs complied with the requirement of environment protection and water resource protection because 60% of the water resource of UB comes from the eastern area. The water source has caused other issues for the heating system. Because UB has a long and narrow shape from east to west and the heat sources are located in the west area with the development of urban area heading east, the spatial configuration of the district heating system has become a long tree-like shape. Heat energy generated by CHP2,3&4 has to be delivered to consumers via a total 290 km of pipeline with diameters ranging DN150~DN1200 and via eight booster pump stations. Currently, the maximum


Appendix 3-17

distance between the heat source and customers reaches 25 km. Hence, the hydraulic balance of the heating system is undermined.

38. Besides the district heating system, many HOB heating systems with direct connection were used in separate district heating areas. In these systems, hot water from the boiler was directly provided to consumer’s radiators. The advantages of the system are its simple and direct connection with low capital investment. The system has only one closed loop which connects the heat source, transmission pipelines, and the consumer’s system. However, problems arise should any portion of the system is damaged, such as a pipeline leak or rupture causing the entire system to be affected. The direct connection is only suitable for the smaller heating systems with hot water temperatures lower than 100°C.

2. Potentials to Expand Heating Coverage

39. From the point of view of heating technologies, the most preferable site for the proposed CHP5 is at the east edge of the urban area. The existing CHPs can be disconnected with the existing eastern heating area, and be connected to the northern and western new development areas. Meanwhile, the CHP5 and CHP3 HP system will mainly covers the east area of UB, as shown in the Figure 2.5. In this case, it will decrease the maximum distance between the heat source and customers, improve the hydraulic balance of the heating system and reduce the electricity of circulating pumps and/or relay pumps.

Figure 2.5 Expected Coverage of the CHPs

Source: District Heating Company of UB

40. In addition, in accordance with the Study by JICA Team, two new towns are planned to be developed, namely a “Science and Technology Town (UB West)” and a “Knowledge City” to accommodate more or less 100,000 persons in the new urbanization areas. The new towns are to be located along the two urbanization corridors, i.e. the West and South-West corridors, within a 20-km radius from the existing CBD. The CHP4 can extend the heating service to the new towns. Meanwhile, many newly built apartments in the east were heated by HOBs, which cannot be connected with the existing heating system. These apartments can be connected with the district heating system. The existing HOB houses can be used as heat exchanging stations, which will save civil work and conserve land use for construction of the new heat exchanging stations. The feasibility to connect the CHP5, recommended to be constructed in the CHP3 site, with the customers in the east of UB is described in the following sections.

D. Energy Efficiency and Performance of Existing District Heating System

41. There are eight booster pump stations (BPS) in the district heating network in UB. Electricity consumption of these BPSs was 15.0 million kWh in 2009. Annual electricity


Appendix 3-18

consumption for the circulation pumps and water pumps was 47.6 million kWh in 2009. Total electricity consumption of the district heating network of UB is 62.6 million kWh. In 2009, the total heat supply was 4.46 million Gcal. The electricity consumption per Gcal heating supply is 14 kWh/Gcal, which is much higher than the international level of less than 7 kWh/Gcal. For the first nine months of 2010, the electricity consumption reached 29.7 million kWh. Details of electricity consumption and water leakage are provided in Table 2.9 and Table 2.10.

Table 2.9: Electricity Consumption for Heat Distribution (kWh)

Months CHP2 CHP3 LPP CHP3 HPP CHP4

Jan 586,416 1,621,704 3,896,086

Feb 536,840 1,433,097 3,212,775

Mar 603,440 1,276,270 3,303,815

Apr 297,930 969,870 2,669,325

May 316,008 1,971,629

June 1,318,521

July 1,441,811

Aug 1,490,219

Sept 61,369 267,651 2,072,691

Oct 358,720 1,121,388 3,133,691

Nov 538,328 1,430,770 3,577,820

Dec 706,000 1,454,016 3,593,777

2009 2,375,060 3,689,043 9,890,774 31,682,161

Jan 679,588 1,554,532 4,061,634

Feb 575,386 1,430,080 3,472,425

Mar 509,232 1,229,310 3,437,162

Apr 424,880 971,050 2,785,354

May 350,100 1,790,256

June 1,325,019

July 1,348,459

Aug 1,227,739

Sept 13,240 333,960 1,717,862

2010 484,299 2,202,326 5,869,032 21,165,910

Note: LPP – low-pressure part; HPP – high-pressure part

Source: National Dispatching Center


Appendix 3-19

Table 2.10: Water Leakage in District Heating System

Day

CHP2 CHP3 LPP CHP3 HPP CHP4 UB DH Company

Gdh Gaw Leak Gdh Gaw Leak Gdh Gaw Leak Gdh Gaw Leak Gdh Gaw Leak

m3/h % m3/h % m3/h % m3/h % m3/h %1 800 7 0.9 3,251 105 3.2 3,960 141 3.6 9,743 344 3.5 17,754 598 3.4

2 806 9 1.1 3,181 94 3 3,929 146 3.7 9,749 369 3.8 17,664 617 3.5

3 803 7 6.1 3,240 72 2.2 3,837 153 4 9,847 395 4 17,727 626 3.5

4 788 7 0.8 3,270 69 2.1 3,790 136 3.6 9,571 404 4.2 17,418 616 3.5

5 779 7 0.9 3,355 69 2.1 3,844 140 3.6 9,538 428 4.5 17,515 644 3.7

6 799 7 0.3 3,320 54 1.6 3,669 106 2.9 9,515 537 5.7 17,303 700 4

7 786 5 0.2 3,283 69 2.1 3,880 116 3 9,601 535 5.6 17,549 721 4.1

8 779 3 0.1 3,263 59 1.8 3,904 109 2.8 9,571 523 5.5 17,517 691 3.9

9 777 5 0.2 3,270 60 1.8 3,893 110 2.8 9,574 532 5.6 17,515 703 4

10 780 0 0 3,261 59 1.8 3,897 117 3 9,577 539 5.6 17,515 715 4.1

11 774 0 0 3,288 58 1.8 3,902 138 3.5 9,578 511 5.3 17,542 707 4

12 772 0 0 3,292 67 2 3,949 130 3.3 9,536 511 5.4 17,549 709 4

13 756 0 0 3,253 70 2.2 3,977 144 3.6 9,521 531 5.6 17,507 745 4.3

14 775 0 0 3,209 64 2 3,947 116 2.9 9,546 485 5.1 17,478 665 3.8

15 774 0 0 3,274 58 1.8 4,029 118 2.9 9,625 503 5.2 17,702 679 3.8

16 746 0 0 3,313 59 1.8 4,123 120 2.9 9,625 538 5.6 17,807 717 4

17 736 0 4.6 3,353 59 1.7 4,076 113 2.8 9,760 528 5.4 17,925 700 3.9

18 745 0 0 3,315 64 1.9 4,007 117 2.9 9,850 486 5 17,918 669 3.7

19 752 0 0 3,271 68 2.1 3,925 116 3 9,909 455 4.6 17,858 639 3.6

20 766 2 0.3 3,255 72 2.2 3,900 127 3.3 9,733 436 4.5 17,654 637 3.6

21 762 0 5.8 3,250 63 6.9 3,882 131 3.4 9,768 459 4.7 17,662 652 3.7

22 768 0 0 3,261 64 2 3,914 129 3.3 9,805 503 5.1 17,747 695 3.9

23 775 0 0.1 3,262 63 1.9 3,980 130 3.3 9,888 505 5.1 17,905 699 3.9

24 778 0 0 3,226 60 1.9 3,977 120 3 9,942 5,822 5.2 17,922 702 3.9

25 804 0 0 3,261 69 2.1 3,945 116 2.9 9,839 506 5.1 17,849 691 3.9

26 790 0 0 3,325 70 2.1 3,888 124 3.2 9,809 501 5.1 17,812 695 3.9

27 810 1 0.1 3,332 70 2.1 3,876 129 3.3 9,888 466 4.7 17,905 666 3.7

28 782 0 0 3,273 52 1.6 3,863 130 3.4 9,821 491 5 17,739 672 3.8

29 750 0 4.9 3,267 53 1.6 3,874 126 3.2 9,828 502 5.1 17,718 680 3.8

30 755 0 0 3,298 61 1.9 3,092 124 3.2 9,873 507 5.1 17,828 692 3.9

31 747 0 0 3,258 66 2 3,879 126 3.3 9,864 493 5 17,748 686 3.9

Aver 775 2 0.9 3,275 66 2.2 3,891 126 3.2 9,719 656 5 17,686 678 3.8

Source: National Dispatching Center (data as of January 2010) Note: Average water leakage is calculated when flow rate G=17686 ton/hr and make-up water flow rate = 687 ton/hr or roughly 3.8 %.


Appendix 3-20

E. Issues

42. Improvement of Existing Heating System. The existing heating system suffered serious water and heat losses as a result of degenerated pipeline system, and poor insulation. In order to achieve technical and economical improvement in the heating supply system of the city, it is required to take effective measures to prevent water losses, to install variable frequency pumps at the CHPs, and to improve the insulation of network with the pre-insulation polyurethane foam (PUR).


Appendix 3-21

III. POWER SUPPLY IN UB

A. Power Plants in Mongolia

43. There are seven main coal-fired power plants in Mongolia with total installed capacity of 856.3 MW as shown in Table 3.1. The CES, with 95% of share in the total installed capacity is the largest energy supply system in Mongolia. The total installed capacity of the CES is 814 MW. Due to aged, deteriorated, and unreliable equipment, the actual available power capacity is 615 MW. Three large-sized power plants, including CHP2, CHP3 and CHP4 located in UB, account for 90% of total installed capacity in the CES. In addition, Erdenet Plant and Darkhan Plant with total 60 MW installed capacity has 10% of share in the total installed capacity in CES. Due to the small capacity of Erdenet Plant and Darkhan Plant, we will not describe them in detail in this report and we will only present the situation of three larger CHPs in UB. The typical performance indicators of the three CHPs in 2009 are shown in Table 3.2. In the following paragraphs, we will describe the three power plants in detail in terms of power generation.

Table 3.1: Coal-Fired Power Plants in Mongolia

No. Thermal Power Plants

Capacity (MW)

Available capacity

(MW)

Share in CES (%)

Location Installationyear

Efficiency(in 2009)

1 CHP2 21.5 18 2.7% UB 1961 21.0

2 CHP3 136 105 17.5% UB 1968 38.6

3 CHP4 580 452 70.2% UB 1983 40.1

4 Erdenet Plant 28.8 39 6% Erdenet city 1987 40.8

5 Darkhan Plant 48 21 3.6% Darkhan city 1965 28.5

CES Subtotal 814.3 615 100% --

6 Dornod Plant 36 -- -- Dornod aimag 1969 19.4

7 Umnugobi Plant 6 -- -- Umnugobi aimag 2001 --

Total 856.3


Table 3.2: Typical Performance Indicators of the CHPs in 2009

Parameter Units CHP2 CHP3 CHP4 CES

Total Power Generation Million kWh/a 120 655 2,711 3,876

Total Power Net generation Million kWh/a 100 520 2,329 3,259

Internal Consumption % 16 21 14 16

Specific equivalent fuel consumption Gr/kWh 610 359 307 --

Efficiency % 21 39 40 --


1. CHP2 Plant

44. CHP2 was put into operation in 1961 when two sets of turbines and generators were installed, each with 6 MW of power generation capacity. In 1969, CHP2 was expanded adding one turbine and generator combination with 12 MW of capacity raising total installed capacity of CHP2 to 24 MW. One condensing turbine AK-6 was modified and changed to a


Appendix 3-22

backpressure turbine, and the installed power capacity of the PP decreased to 21.5 MW With an available power generation capacity of 18 MW. Detailed information of the turbine and generators are shown in Table 3.3 and 3.4.

Table 3.3: Key Information on Turbines in CHP2

No. Model Year of Commencement

Installed Capacity(MW)

Steam Pressure (kg/cm2)

Steam Temperature (°C)

1 AK-6-35 1961 6 35 435

2 R-4-35 1961 3.5 35 435

3 PT-12-5/10 1969 12 35 435


45. Table 3.2 shows that in 2009 the power generation of CHP2 was only 3% of the total power generation of CES. Moreover, its specific equivalent fuel consumption for power generation was as high as 600 Gr/kWh, while the internal power consumption rate reached 16%. The higher specific equivalent fuel consumption and internal power consumption resulted in a lower efficiency of 21%. Due to poor emission controls on the power plants the air pollution is serious. These indicators explain the urgency and necessity to retire CHP2.

Table 3.4: Key Information on Generators in CHP2

No. Model Year of Commencement Installed Capacity (MW)

Voltage Level(kV)

1 TQC-5466-2 1961 6 6.3

2 TQC-5466-2 1961 3.5 6.3

3 T2-12-2 1969 12 6.3


2. CHP3 Plant

46. CHP3 has both high and low pressure systems. Four low pressure units of turbines and generators with 39 kg/cm2 of working pressure, each with 12 MW of power generation capacity, were installed on 1 December 1973, and four high-pressure units of turbines and generators with 100 kg/cm2 of working pressure, each with 22 MW of power generation capacity were installed in 1977. The detailed technical information of the units is in Tables 3.5 and 3.6. Currently, this power plant has an installed capacity of 136 MW, and the available capacity is 105 MW. CHP3 covers 17 % of electricity demand of CES.

Table 3.5: Turbines in CHP3


Installed Capacity

(MW) Steam Pressure

(kg/cm2) Steam

Temperature (°C)

1 PT-12-35/M10 1973 12 35 435 2 PT-12-35/M10 1973 12 35 435 3 PT-12-35/M10 1974 12 35 435 4 PT-12-35/M10 1975 12 35 435 7 PT-25-90/M10 1977 22 35 435 8 PT-25-90/M10 1977 22 35 435 9 PT-25-90/M10 1978 22 35 435

10 PT-25-90/M10 1979 22 35 435



Appendix 3-23


No. Model Year of Commencement Installed Capacity(MW)

Voltage Level(kV)

1 T2-12-2 1973 12 6.3 2 T2-12-2 1973 12 6.3 3 T2-12-2 1974 12 6.3 4 T2-12-2 1975 12 6.3 7 TBS-32 1977 22 6.3 8 TBS-32 1977 22 6.3 9 TBS-32 1978 22 6.3

10 TBS-32 1979 22 6.3


47. From Table 3.2, we see that the internal power consumption rate is high at 21%. Although both its specific equivalent fuel consumption and internal power consumption rate are higher than the CHP4, its efficiency reaches 39%, which is close to CHP4. However, this higher efficiency of CHP3 does mean that it is an efficient plant. CHP3 has a relatively high efficiency because its ratio of heat output to power output 3:1 which is quite high. Considering this higher ratio, we conclude that CHP3 is not efficient. In addition, emissions from power plants are unregulated, which results in serious air pollution.

3. CHP4 Plant

48. CHP4 is the biggest coal-fired CHP in Mongolia. It covers 70% of the total electricity demand of the Central Energy System (CES) of Mongolia. The installed capacity of the CHP4 is 580 MW in electricity generation, and the available capacity is 452 MW. The details of the power generation units are shown in Table 3.7 and 3.8. CHP4 was designed and constructed by former USSR's equipment suppliers. Upon withdrawal of Russian economic support and the return of Russian specialists in 1991, the CHP4 has faced a serious shortfall of electricity and heat supply due to lack of skilled staff and necessary spare parts. The Government of Japan has supported the implementation of several Grant Aid and Soft Loan projects to improve the condition of CHP4 which has subsequently improved the welfare of people in Mongolia. As a result of this support, the condition of CHP4 has greatly improved, heat and electricity generation have been increased, auxiliary power consumption was reduced, fuel consumption was reduced, specific power generation cost was reduced, critical full stop emergency situations have been eliminated and the number of unplanned shortages was decreased. Compared to CHP2 and CHP3, CHP4 has the lowest internal consumption rate and specific equivalent fuel consumption, and the highest efficiency. In addition, it is the major power and heat source for UB.

Table 3.7: Key Information on Turbines in CHP4


Installed Capacity

(MW)

Steam Pressure (kg/cm2)

Steam Temperature

(°C) 1 PT-80/100-130-13 1983 80 130 555 2 T-100/120-130-4 1983 100 130 555 3 T-100/120-130-4 1983 100 130 555 4 T-100/120-130-4 1983 100 130 555 5 PT-80/100-130-13 1983 100* 130 555 6 PT-80/100-130-13 1983 100* 130 555



Appendix 3-24


No. Model Year of Commencement Installed Capacity (MW)

Voltage Level(kV)

1 TBPh-120-2UZ 1983 80 6.3

2 TBPh-120-2UZ 1984 100 6.3

3 TBPh-120-2UZ 1985 100 6.3

4 TBPh-120-2UZ 1986 100 6.3

5 TBPh-110-2UZ 1990 100(80*) 6.3

6 TBPh-110-2UZ 1991 80 6.3

*Note: Initial generation capacity was 80 MW. It was increased to 100 MW through modification of turbine.


B. Power Supply

49. As above mentioned, electricity is supplied through three centralized power grids and two isolated systems, including CES, EES, WES, the Dalanzhadgad system, and the Zhavhan and Gobi-Altai aimags system. The CES covers 14 aimags and is connected to the capital UB, Darkhan, an iron-making city, Erdenet, a copper-mining city, and Baganuur, a coal-mining city. EES provides power to the Sukhbaatar Aimag. WES constantly supplies power to the western three aimags, while the Dalanzhadgad system only provides electricity to the local area. The Zhavhan and the Gobi-Altai aimags are interconnected to the Taishir hydropower plant. In addition, inhabited areas which are not connected to those systems have diesel power stations in aimags and soums. Seven coal-fired power plants, two hydro power plants, separate diesel generators, and small renewable energy generators form the network of power sources.6

50. The CES is the biggest power generation and transmission system. It has five electricity generation companies, one transmission company, and four distribution companies. The generation companies have 814 MW of installed capacity, of which 580 MW or 70% of power is generated by the CHP4. The CES electricity grid reaches about 79% of the population and covers 60% of the country’s surface area, including the capital city and the surrounding fourteen aimags. The system’s peak electricity demand was 695 MW in 2009. This system provides 95% of the total electricity consumption for the whole country.

51. In 2008, the total electricity supplied to the CES from the power stations and imported from Russia was 3,112 GWh. Out of that 3,112 GWh, the Transmission Company sold 3,008 GWh of electricity to the distribution licensees and large consumers. The balance of 104 GWh went to substation internal consumption and transmission losses. Table 3.9 shows the energy balance of CES from the gross generation of the power plants in 2008. The gross generation was 3,570 GWh with the station consuming 588 GWh or about 16% of the gross generation. The consumed energy within UB accounted for 43% in the total supply and the amount consumed by Erdenet Copper Mine was 26% of the total supply of CES.

6 Energy Regulatory Authority of Mongolia, 2010, Framework for Setting Energy Tariffs and Prices in Mongolia.


Appendix 3-25

Table 3.9 Summary of Energy Balance in 2008

Items GWh Share in Gross Generation

Share of Total Supply

Share of Sold Electricity

Share of Consumption

Gross Generation 3,570 100%

Internal Consumption 588 16%

Net Generation 2,982 84% 96%

Import from Russia 130 4%

Total Supply to CES 3,112 100% 100%

Substation Internal Consumption and Transmission Loss

104 3%

Total Sold Electricity 3,008 100%

of which consumed in:

Within UB 1,329 44% 43%

Outside UB (Erdenet Copper Mine)

1,688 (795)

56% (26%)

54% (26%)

Source: ERA’s Reference Book on Energy Licensed Companies and Entities, 2009.

52. From 2008 to 2010, the electricity supply and consumption has increased rapidly averaging a 7-8% annual increase. The total electricity supplied to the CES from the power stations and imported from Russia was 3,619 GWh in 2010, indicating a 7.9% an annual increase from 2008 to 2010. Out of 3,619 GWh, the Transmission Company sold 3,503 GWh of electricity to the distribution licensees and large consumers. The balance of 115 GWh went to internal consumption and transmission losses. Table 3.10 shows the energy balance of CES from the gross generation of the power plants in 2010. The gross generation was 4,127 GWh with a 7.5% annual increase from 2008 to 2010. The power station consumed 645 GWh accounting for 16% of the gross generation. The consumed energy within UB accounted for 48% in the total supply and the amount consumed by Erdenet Copper Mine was 27% of the total supply of CES.

Table 3.10 Summary of Energy Balance in 2010

Items GWh Share in Gross Generation

Share of Total Supply

Share of Sold Electricity

Gross Generation 4,127.10 100%

Internal Consumption of Power Plants

644.57 15.6%

Net Generation 3,482.52 84.4% 96.2%

Import from Russia 157.49 4.4%

Export to Russia 20.69 -0.6%

Total Supply to CES 3,619.32 100%

Substation Internal Consumption and Transmission Loss

115.38

Total Sold Electricity 3,503.94 100%

of which consumed in:

Within UB 1,683.68 48.05%


Appendix 3-26

Outside UB 745 21.26%

(Erdenet EDN including Copper Mine)

938.83 26.79%


53. The electricity grid of the CES consists of a large 220 kV and 110 kV transmission network. It comprises 6 substations at 220 kV and 54 at 110 kV. The largest 220 kV substation has transformation capacity of 2 x 125 MVA, and the transformation capacity of thirteen 110 kV substations located in UB area varies from 2 x 6.3 MVA to 2 x 25 MVA. The primary distribution system in UB of 208 substations is mainly at 35 kV.

54. A 220 kV ring system interconnects the principal generation and load centers of UB, Darkhan and Erdenet, and there are an additional 220 kV interconnections with load centers of Baganuur and Choir. The CES 220 kV grid is connected to the Russian system by a 220 kV double circuit line (about 300 MW total transmission capacity) with the connection point at the substation in Selendum, near the Russian Gusinozersk power plant. The total length of the 220 kV transmission network is about 1,705 route km, of which 911 km are double circuit lines and 794 km single circuit lines.

55. The CES transmission system also consists of a fairly large 110 kV grid connecting the main system substation and load centers. The total length of the existing 110 kV network is around 3,465 route km, which is roughly subdivided into 4 sub-networks, which are centered in UB (206 route km), Baganuur (743 route km), Darkhan (676 route km), and Erdenet (627 route km). At the distribution substations, the voltage is stepped down to 35 kV or 10 kV and a few to 6.3 kV. Substations are typically equipped with two parallel transformers of identical size (e.g. 2 x 25 MVA, 2 x 16 MVA or 2 x 10 MVA). The total installed transformer capacity (excluding the generator transformers) amounts to nearly 2,200 MVA. Transmission voltages are 220 kV (in the CES only) and 110 kV, while principal medium distribution voltage is 35 kV, which is further stepped down to 10 kV or 6 kV. The approximate total length of installed transmission lines from 2007 (in route km) are summarized in Table 3.11.

Table 3.11: Transmission and Distribution Systems in CES (2009)

Voltage Level Transmission Line (km) Number of Sub-Stations in CES Total MVA in CES

220kV 1,044 6 1,128

110kV 2,982 54 1,160

35kV 5,820 178 500

15kV 1362 31

6– 10kV 8,343 2875 -

Total 19,551 3,144 2,788


C. Power Demand

1. Power Demand Forecast Made by NDC

56. The National Dispatching Center (NDC) is the organization required by its license obligations to perform electrical demand forecasting for all systems in Mongolia. An Energy Sector Master Plan was developed with the support of the ADB in 2001. Due to unsuccessful implementation, this Master Plan is now obsolete and must be redeveloped. The NDC has revised the Master Plan with long-term load forecasting, as shown in the Table 3.12 below.


Appendix 3-27

Table 3.12 Power Consumption Forecast Made by NDC (GWh)

Years 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2025 2030

UBEND 1,774 1,898 2,032 2,174 2,327 2,490 2,664 2,851 3,051 3,265 4,580 6,423

Erdenet EDN 944 961 986 1,025 1,102 1,153 1,169 1,194 1,210 1,227 1,321 1,424

Darkhan EDN 444 448 452 519 521 523 527 529 533 540 597 659

Baganuur EDN 238 240 242 245 247 250 252 253 254 255 275 304

Khuvsgul Energy 26 27 29 30 31 32 33 34 35 36 43 52

Bayanhongor Energy 31 37 45 57 75 88 101 117 134 158 219 236

Erdenet Amidral co 19 20 20 20 21 21 21 21 21 21 21 21

Erchim Suljee Co 20 23 24 24 25 26 27 28 28 27 30 33

Railways 41 42 43 44 44 45 46 47 48 49 54 60

Nolgo Co 4 4 4 4 4 4 4 4 4 4 5 5

Transmission losses 122 128 134 143 152 160 167 175 184 193 247 318

Total load (distributed) 3,664 3,828 4,010 4,285 4,549 4,792 5,012 5,254 5,502 5,776 7,392 9,534

Source: NDC

57. This assessment is still different from the actual demands during 2008 and 2009. In 2008, the actual demand was at the average scenario of the planned 2015 level, indicating that for 2008, the forecast is about six years behind of real demand growth.

2. Power Demand Forecast Made by Municipal Governor’s Office

58. The Municipal Governor’s Office of UB plays a significant role in forecasting UB city electrical demand, which is prepared based on analysis made on UB development plans coordinated by UB Municipal Government. According to the main UB city development plans for the next 10 years, several construction programs will be initiated. By 2020, power demand will mainly occur in the following areas:

Construction of apartment buildings and related service constructions within existing apartment housing districts. Expected additional demand for these areas will be about 157 MW by 2020 with about 5% of average annual growth of demand in these districts.

Ger areas which will remain until 2020. The power load density at these parts of UB is relatively low, but these districts occupy a large area. Demand growth for these areas will be increased at an annual rate of 7%. In 2020, 70.4 MW of additional demand is estimated to arise from these areas.

Ger areas to be replaced by new apartment building districts. By 2020, 166.8 MW of new power will be needed for this development.

Apartment districts to be built in the city in reserved areas by 2020. There are five main free areas reserved for these new districts. According to construction plans, this growth will add 188.7 MW of demand in 2020.

59. Considering also the growth of demand in CES areas outside of UB where the average growth of last two years was 3-5%, and based on the above power demand estimate by 2020, the anticipated growth profile of the additional power demand for UB for the next 10 years is shown in Figure 3.1.


Appendix 3-28

Figure 3.1: Additional Power Demands for UB City up to 2020.

Source: UB Municipal Governor Office

3. Power Demand Forecast Made by TA Team

60. In addition, the demand for power will increase significantly after 2014 when the Gobi mining area is expected to be connected to the CES. Electrical energy needs will increase significantly after 2014, when according to information given by Ouytolgoi staff, the Gobi mining area expected will be connected to the CES. The power demand of Gobi mining area is shown in the following Table 3.13.

Table 3.13 Demand Forecast in Gobi Mining Area (MW)

Years 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019

Power Demand (MW) 0 141 143 164 217 232 310 320 324 330 335

Source: http://mmre.energy.mn/branch/type/104/113/

61. In combination with the power demand in the existing CES and Gobi mining Area, we have forecast CES demand growth using an integrated econometric and end-use approach, which allows integration of physical and behavioral factors in a common framework. While the econometric relationships would internalize the influence of economic and policy effects, the end-use approach provides an accounting plane for aggregating end-use and sector energy demands projected into the future. In addition, the Gobi mining area will be interconnected to the CES in 2015, which will be included in the following demand growth scenarios, as shown in Table 3.14.

Table 3.14 Power Demand Forecast by 2030

Years 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2025 2030

Total demand

(MW)

high 763 820 863 935 1,314 1,401 1,490 1,552 1,633 1,736 2,040 2,344

average 762 819 862 934 1,313 1,394 1,483 1,544 1,625 1,728 2,030 2,321

low 761 818 861 933 1,310 1,391 1,480 1,541 1,622 1,702 1,990 2,274

Source: TA Team Estimation

51.7104.2

157.8

211.8267.2

310.2346.2

383.3421.5

462498.7

0

100

200

300

400

500

600

2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020


Appendix 3-29

Table 3.15: Balance Sheet of Power Supply and Demand by 2030


62. Because the primary purpose of the CHP5 is to meet the heating demand as mentioned in above Chapter, it will not fully meet the additional power demand of the CES system. The power supply of the CHP5 is proposed to be 450 MW by 2015, and 820 MW by 2020. The detailed size of the CHP5 is seen in Appendix VI of this report. Based on the power demand forecast above and the power supply capacity of the existing power plants, we prepared the balance sheet for power supply and demand by 2030, as shown in Table 3.15. As the power demand increases, the existing power plants and new-built CHP5 cannot fully meet the demand. The remaining power demand should be covered by other sources, such as import from other countries or constructing now power plants. By 2015, the balance that should be covered by other power sources is 158 MW in additional to Phase I of CHP5. By 2020, the balance will be 93 MW assuming the Phase II of CHP5 would be operational by this year and the balance will be 686 MW by 2030.

D. Connecting the CHP5 with the CES

63. Three sites have been proposed for the CHP5, which will require different grid connection solution: Three sites has been evaluated for the CHP5 site, including:

i) A CHP plant at Uliastai; ii) To build a new power plant nearby the Baganuur coal mine (transmission lines of 140

km to Ulaanbaatar) and HOB’s around the city to separately supply heat; or, iii) To build Phase I of CHP5 within the boundary of the existing CHP3, then demolish the

low-pressure system of CHP3 and build Phase II in its place to complete the new CHP5.

1. Uliastai Location

2011 2012 2013 2014 2015* 2016 2017 2018 2019 2020 2025 2030

10 10 10 0 0 0 0 0 0 0 0 0

120 120 120 120 80 80 80 80 80 80 80 80510 510 510 510 510 510 510 510 510 510 510 51015 15 15 15 15 15 15 15 15 15 15 1540 40 60 60 60 60 60 60 60 60 60 60

695 695 715 705 665 665 665 665 665 665 665 665762 819 862 934 1,003 1,074 1,141 1,214 1,290 1,376 1,661 1,933

0 0 0 0 450 450 450 450 450 820 820 82067 124 147 229 -112 -41 26 99 175 -109 176 448

36 36 36 36 40 40 40 40 100 150 150 15024 0 0 0 0 0 0 0 0 0 0 083 128 181 196 270 280 302 290 235 202 219 238

143 164 217 232 310 320 342 330 335 352 369 388

695 695 715 705 705 705 705 705 765 815 815 8150 0 0 0 450 450 450 450 450 820 820 820

Total Balace of CES (MW) 67 124 147 229 158 239 328 389 410 93 395 686762 819 862 934 1,313 1,394 1,483 1,544 1,625 1,728 2,030 2,321

*- Gobi Mining Area expected to be connected to the Central Grid

Import/Other sources (MW)Gobi area demand (MW)

Years

Total generation (MW)Original CES Demand (MW)

Gobi Mining Area

Central Energy System

Total demand of CES (MW)

CHP-2 (MW)CHP-3 (MW)CHP-4 (MW)Erdenet CHP (MW)Darkhan CHP (MW)

Ukhaahudag CHP (MW)

CHP-5 (MW)

Power BalanceTotal generation of exisitng power

Oyutolgoi diesel plant (MW)

CHP-5 (MW)Import/Other sources (MW)


Appendix 3-30

64. There could be two different solutions to grid connection and they are as follows:

i) If there is enough space for a 220kV substation, a 220 kV GIS should be constructed. The CHP4 – Baganuur line will enter into the CHP5 GIS and exit to Baganuur. The Figure 3.2 shows the substation of CHP5 connection diagram.

Figure 3.2: CHP5 220 kV Gas Insulated Substation

Source: TA Team

ii) An alternative option is to use and extend the existing Ulaanbaatar 220/110/35 kV substation (4 km from proposed location) as CHP5 substation. The existing UB 220/110/35 kV Substation connection diagram is shown in Figure 3.3, and the proposed UB 220/110/35 kV substation extension diagram is seen in Figure 3.4.

Figure 3.3: Existing Ulaanbaatar 220/110/35 kV Substation

Source: TA Team


Appendix 3-31

Figure 3.4: Proposed Ulaanbaatar 220/110/35 kV Substation Extension

Source: TA Team

2. Baganuur Conventional Coal-Fired Power Plant 65. If a conventional coal-fired power plant will be constructed in Baganuur, the 220 kV GIS, as shown in Figure 3.5 should be constructed. In addition, because the power will be mainly transmitted to UB, the existing 220 kV double line (300mm2 double line, approximate loading capacity 300 MW) is unable to conduct full load power to the system. A new double circuit 220 kV, 120 km line shall be built and connected to Ulaanbaatar 220/110/35 kV substation, with an extension of the 220 kV side of the Ulaanbaatar 220/110/35 kV substation.

Figure 3.5: CHP5 GIS Substation at the Location of Baganuur

Source: TA Team


Appendix 3-32

3. Building CHP5 on the location of CHP3 66. The existing CHP3 110/35 kV substation cannot carry any more than 820 MW. A new 220/110 kV GIS needs to be built. Hence, four 220 kV circuits shall be built and connected to the nearest 220 kV system. There are three options for grid connections:

i) Connect two circuits to the CHP4 220 kV substation and two lines to the existing 220 kV line to Erdenet;

ii) Connect two circuits to the CHP4 220 kV substation and two lines to the existing 220 kV line to Baganuur;

iii) To provide a high capacity and high reliability connection to the Gobi mining area, building a 330 kV GIS at the CHP5 with additional double line construction to the Gobi mining area (about 700 km) is a high initial investment cost solution, but is more feasible when considering future grid development.

67. The existing 110 kV substation shall be modernized. To supply existing 35 kV customers, an upgrade of one of the existing 35 kV substations or 110/35 kV substation will be required. The diagram of grid connection is shown in the Figure 3.6. The CHP5 will be connected to the power system at the 220 kV line. The outgoing line goes to the CHP4 and the Erdenet 220 kV substation. In the plant, a 220/110 kV GIS will be established. The length of each line to the CHP4 is approximately 4.5 km. The length of the 220 kV double circuit line to connect to Erdenet existing line is also 4.5 km.

Figure 3.6: CHP5 GIS Substation at the Location of Existing CHP3

Source: TA Team

E. Issues

68. Outstanding issues for clarification before finalizing electricity demand forecasting and electricity balance planning:

i) There are a number of different forecasts developed by different organizations. It’s understood that the NDC is the entity legally responsible for demand forecasting. Thus, it’s important to ensure that the NDC is coordinating its forecasting activity with appropriate stakeholders such us the UB Government.

ii) There is no clear policy identified for the retirement of aged CHPs; different assumptions exist on this issue.

iii) Generally, the transmission system has the reserves to supply the growing demand in UB. But by the year 2015, it will be required to reinforce the existing 110 kV ring line around UB. The distribution system already faced problems of the overloading of distribution assets. Continuous reinforcements and construction of new substations are required for the distribution system during the next 10 years.


Appendix 3-33

IV. FUEL SUPPLY

A. Coal Resource

1. Coal mine situation

69. In general, Mongolia is one of the most resource rich countries in the world and coal is one of the Mongolia’s most important mineral resources. It is estimated that Mongolia’s total proven coal reserves are 12 billion tons and productive resources are 6.2 billion tons. At present, more than 200 coal deposits within 12 coal basins and 3 regions are known in Mongolia. There are 40 licensed coal mines with different capacity around the country. Most coals are sub-bituminous to lignite in the east and bituminous in the west. In 2009, total coal production was 7.7 million tons per year, of which 5.23 million tons were used for power generation. 70. However, Mongolia is still a developing country. The infrastructure for mass production at many of the mines is not in place yet. Therefore, the selection of the coal supply for the newly proposed power plant in UB has to be based on several criteria including i) the mine must have existing infrastructure for mass production or the capacity to increase production to satisfy any expansion needs; ii) coal reserves must big enough for decades of exploration/excavation; iii) production or potential production capacity must be sufficient to supply the power plant’s normal, stable operations; iv) the distance between UB and the source of supply must be economically reasonable; v) the heating value of the coal must be commercially available; and, vi) that a transportation system for shipping coal to the destination is available.

71. Most existing mines in central Mongolia and around Ulaanbaatar are lignite coal and heating value is around 3,000 kcal/kg. Therefore, very long transportation distances are not suitable for these types of coal and the coal transportation distance has to be limited to maintain economic viability. Figure 4.1 is a map of mine deposits which shows coal mine distribution within a 300 km liner distance from UB. These coal mines are at Baganuur, Shivee-Ovoo, Alagtogoo, Khashaaj Khudag, Saikhan-Ovoo, Shariin Gol and Tsogt Gol. Within these reserves, only Baganuur and Shivee-Ovoo deposits have large enough reserves to supply the CHP5 power plant over the next 20-30 years.


Appendix 3-34

Figure 4.1: Coal Mines in Central Mongolia

MANDALGOVI

DARKHAN

ERDENET

UNDURKHAAN

ULAANBAATAR

ZUUNMOD

GOVISUMBER

SHIVEE-OVOO

SHARIIN GOL

KHASHAAT KHUDAG

ALAGTOGOO

SAIKHAN-OVOO

TEVSHIINGOVI

KHUUT

TSOGT GOL

NALAIKH BAGANUUR

KHANGAI

CHANDGANA TAL

BERKH

Source: TA Team.

2. Production, Sales and Transportation

72. The preliminary FS has shown that there will be about 3.62 million tons coal need for the CHP5 power plant per year based on its current design capacity. Based on an analysis of the mines around UB, it has been proposed that the CHP5 power plant will derive 30% of its coal from Baganuur and 70% from Shivee-Ovoo. In 2009, Baganuur produced about 3 million tons of coal while Shivee-Ovoo produced 1.4 million tons coal which is near to the capacity of both mines. The majority of these coals are supplied to UB for power production. Therefore, neither of them can meet the further demand from CHP5 without expansion.

73. The Baganuur coal deposit with proven coal reserves of 713.1 million tons and productive resources of 515.5 million tons is located in about 110 km east of UB. The mine was designed by experts from the former Soviet Union to operate at 6 million t/y of coal, but it never reached its design capacity. In 2009, production was 3 million tons with the coal quality having high moisture and ash contents. Currently, Baganuur is providing its coal to a power plant in UB. The major necessary production infrastructure and loading to nearby railway ports are already in existence.

74. The Shivee-Ovoo coal mine was opened in 1992 and is located 260 km southeast of UB. It has proven coal reserve of 2 billion tons and productive resources of 564.1 million tons. The mines were designed by the Mining Institute of Mongolia. It produced 1.4 million t/y of coal in 2009. Like Baganuur, Shivee-Ovoo is providing its coal to power plants in UB. The major production infrastructure and loading to nearby railway ports are already in existence.

75. During 1995-2000, all medium and small-scale coal mines were privatized, but these two large mines have remained as state owned property. CHP2, CHP3 and CHP4 get their coal from these two mines. In 2009, these two mines provided 3.8 million tons to UB power plants. Although current production in either of these mines cannot support the demand for coal for CHP5, they do have the infrastructure in place and there is potential for expanding the existing mines or development of new mines on these sites. When CHP5 is completed, the option to close CHP3 and/or CHP2 can free up coal to be used by CHP5.


Appendix 3-35

B. Coal Quality

76. A summary of the characteristics of coal from the Baganuur and Shivee-Ovoo deposits is shown in Table 4.1. The Baganuur coal is a lignite coal with a moisture content as high as 33% an ash content of about 9.5% and a heating value of about 3,400 kcal/kg. With a sulfur content of 0.36% it is considered a low-sulfur coal.

Table 4.1: Coal Characteristics of Baganuur and Shivee-Ovoo Coal Mines

Name of Deposit

Moisture Content

(%) Ash (%)

Volatile Matter

(%)

SulfurContent

(%) Heating Value

MJ/kg kcal/kg

1 Baganuur 33 9.5 43.9 0.36 14.4 3,400

2 Shivee-Ovoo 40.7 8.9 42.7 0.9 11.7 2,900


77. The Shivee-Ovoo coal is a lignite coal with moisture content as high as 40% an ash content of about 8.9% and a heating value of about 2,900 kcal/kg. It has a sulfur content of 0.9%. An analysis of composition of these coals is also summarized in Table 4.2.

Table 4.2: Composition Analysis of Coal Samples

Coal Mine

Combustible Matter (dry and ash free) (%) Combustible Matter (as received) (%)Carbon Hydrogen Sulfur Oxigen Nitrogen Carbon Hydrogen Sulfur Oxigen Nitrogen

Baganuur 72.3 4.55 0.57 21.67 0.91 39.7 2.5 0.313 11.9 0.5

Shivee- Ovoo 67.6 5.4 1.76 24.1 1.14 34.34 2.74 0.9 12.24 0.58


C. Coal Consumption Estimation

78. In accordance with the demand forecast, the coal consumption was estimated in terms of hourly, daily, heating season, and yearly consumption. The daily and hourly coal consumption is obtained from the hourly coal consumption of each boiler multiplied by boiler quantities (eight in the heating season and six in non-heating season) and operation hours of each day (20 hours), as shown in Table 4.3. The amount of coal consumed by the plant during the heating season is obtained by multiplying the hourly coal consumption of each boiler by the number of boilers (eight in the heating season and six in the non-heating season) and operation hours of the heating season (4,000 hours) while the operation hours of the non-heating season is 1,500 hours. The boiler is expected to work 5500 hours per annum. The yearly amount of coal consumed is the coal consumption in the heating season plus that in the non-heating season. Therefore, the total coal consumption will be 3.62 million ton/yr. The amount of estimated coal consumption is shown in detail in the following Table 4.3.

79. Due to the limited productivity at the Baganuur Mine, it has been proposed that the CHP5 power plant get 30% of its coal from Baganuur coal mine and 70% from Shivee-Ovoo coal mine.


Appendix 3-36

Table 4.3 Coal Consumption Estimation

Unit Baganuur Shivee-Ovoo

Heating Seasons

Non heating Seasons

Heating Seasons

Non heating Seasons

Hourly Coal Consumption of Each Boiler ton/hr 102.65 102.65 120.35 120.35

Daily Coal Consumption of the Plant 103 ton/d 12.32 10.27 14.44 12.04

Yearly Coal Consumption of the Plant 106

ton/yr

2.46 0.77 2.89 0.90

3.23 3.79

3.62 (30% from Baganuur, 70% from Shivee-Ovoo)


D. Coal Transportation

80. Mongolia has an existing railway transportation system. The earliest railways date back to 1938, when a 43 km long railway was built between Ulaanbaatar and Nalayh. The Mongolian railway system is actually two separate railways. The Trans-Mongolian main line is 1,110 km long, starting at the border of Russia and Mongolia in the north, passing through UB, and ending at the border of Mongolia and China in the south. The second railway named the Bayantumen Railway is in the north-east, with a length of 239 km running from the Russian border to the center of the Eastern region Choibalsan. The total length of the Mongolia Railway, including branch lines is 1,815 km.

81. The Mongolian Railway is jointly owned by the governments of Mongolia and Russia. More than 95 percent of its freight turnover and 55 percent of its passenger traffic is in Mongolia. The system is a single track line railway and has an 18 million ton capacity/year (each way 9 million). Over the course of many years, 40% of the wooden rail bed has been converted to concrete bed. An express train service for containers being delivered in the Ulaanbaatar-Siangan direction was opened in 2003 and as a result, freight cargo is now being forwarded to clients in just 3 days compared to the previous 10 days.

82. In Mongolia, all east-west transportation depends on roads. However, these roads have very few paved sections. The Government of Mongolia approved the implementation of the Millennium Road Project (total 2,200 km long) to connect long-distance regions by an arterial road. Its goal is to facilitate efficient transportation, industrial and service capability, as well as regional development and improvement of the quality of life. The Millennium Road Plan (MRP) consists of one horizontal (east-west) arterial road designated as the “Millennium Road” which advances the nation in the aspects of settlement and regional development project and five vertical (north-south) arterial roads to stimulate regional development.

83. Currently, the rail system is the only practical option for shipping the mass volumes of coal need for CHP5. The total railway distance from the Baganuur mine to the current CHP3 power plant site in UB is approximately 191 km. The railway distance between the Shivee-Ovoo mine and the CHP3 power plant site in UB is approximately 259 km. Coal is transported by the railway system from both mines to UB power plants. In 2009, 5 million tons of coals were transported from mines to UB using the rail system, while the total transportation loads were 8.2 million tons through railway. This loading amount accounted for more than 90% of the railway’s maximum capacity of 9 million tons.

84. The TA Team has consulted with the Mongolian-Russian Joint Stock Ulaanbaatar Railway (UBTZ). The UBTZ has issued an official letter concerning the requirement and improvement on the existing railway to transport coal for CHP5, which is described as follows:


Appendix 3-37

85. There is no any degradation for coal transport from Shivee-Ovoo, and Baganuur, but 3 lines and one extra engine have to be added at site Shivee-Ovoo substation.

86. The existing transportation scheme is to receive and distribute all coal at the UB-1 substation and deliver from there to CHP3. At present, 40 rail trucks (a railway freight car) of coal are delivered to CHP3 every day. This amount will be increased 3 to 4 times in the future. It may cause traffic jam and affect traffic safety. Therefore, this matter shall be discussed by the city government.

87. The capacity of the UB-1 substation could be sufficient. However, railway lines in vicinity of the CHP3 shall be extended according to precious calculation. The distance between the UB-1 substation and CHP3 is 1.2 km. This branch railway is in poor condition and needs to be repaired and refurbished (adding signals and enforce crossing or even building different level crossings). The detailed study on railway improvement and/or expansion should be done by other project as soon as possible.


Appendix 3-38

V. SITE CONDITION OF THE CHP5

A. General Description of the Site

88. The CHP5 is proposed to be positioned inside the CHP3 Plant, which is located in the southwest suburban of central UB, the major industrial area of UB. It is situated north of Chinggis Avenue, northwest of the Yaarmag Bridge, and near the downstream of the Tuul River. It is about 5 km from the central area of the UB. The detailed location is shown in the attached Drawing TA7502-MON-Z01.

89. The CHP3 covers an area of about 88 ha. Its ash slurry is pumped to on-site ash ponds. The arrangement of built areas of the CHP3 was determined according to existing Russian Standards for Thermal Power Plant Design, and it has some free land inside its property boundaries.

90. The CHP3 has several auxiliary buildings, such as the water treatment section, mechanical workshops, the oxygen station, the warehouse and tanks of heavy oil and lubrication oil. Also, there is mazut station, where heavy oil is heated up and pumped to Boiler Island. The coal handling system has a dumper for coal unloading and a railcar defroster. The capacity of coal yard is 235,000 tons.

91. The CHP3 is still operating normally and provides power to CES and heating service to UB area. The following infrastructure is available: a railway linking the CHP3 and national railway network has been laid and is under use; there is road access to the plant but the road is not well maintained, and suitable rehabilitation of the road is necessary; there are the necessary utilities, such as water, sewage and telecommunication, etc. but the sewage system shall be evaluated and modified; and, the site is in good condition for the CHP5 with a 2.5 km long branch railway.

B. Hydrographic and Meteorological Condition

92. Mongolia has four distinct seasons as shown in Table 5.1. Spring is from April to May and it is dry and windy. Summer is from May to September and is hot it is also the rainy period. Autumn is the transition period from summer to winter, and it is windy and cooler. The extremely cold winter is the longest season in Mongolia. There are three meteorological observation stations in UB city.

Table 5.1: Four Seasons in Mongolia

Season Winter Spring Summer Autumn

Starting 4 November 1 April 23 May 5 September

Finish 1 April 23 May 5 September 4 November

Number of Days 148 52 105 60

Source : Institute of Meterology and Hydrology, 2005.

1. Climatic Regime

93. UB is surrounded by a mountain range which produces an inversed atmospheric temperature distribution, in which the local air temperature will increase as its altitude increases. This is formed in the air layer above the valley of the Tuul River in winter time. Under normal atmospheric conditions, the local air temperature will decrease as its altitude increases. Due to the inversed atmospheric temperature distribution, atmospheric pressure is 2-3 Pa (gauge pressure) higher and atmospheric temperature is relatively lower in the Tuul river valley than in the city center. Temperature inversions play a major role in the air quality,


Appendix 3-39

especially during the winter when these inversions are the strongest.

94. During winter, the warm air above cool air acts like a lid, suppressing vertical natural air convection and limiting air exchange at the surface. As a result, the dispersal of waste particle matters in the air is limited, which leads to poor air quality. Whereas in the warm season, the inversion formed is relatively weak and the mountain-hollow wind dominates.

2. Air Temperature

95. The mean annual temperature in UB city ranges between -0.9оС to 2.4оС, and winter is cold with an average temperature of -19.3оС to -22,5оС. In summer, an average temperature ranges between +14.3оС to +15.3оС. According to the meteorological reports since 1979, the highest temperature reached up to +39.5оC on 15 July of 2001, and the lowest temperature was -46.9оС on 9 January 2001.

96. Average Air Temperature: In accordance with the data from the institute of Meteorology and Hydrology in 2005, the maximum monthly average air temperature of 18.5оC occurred in July, the minimum average monthly air temperature of -25.6оC occurred in January, and the yearly average air temperature was -1.7оC. The detailed average air temperature is shown in Figure 5.1.

Figure 5.1: Average Air Temperature (оC)

Source: Institute of Meterology and Hydrology, 2005.

97. Monthly Maximum Air Temperature: In 2005, July had the highest monthly maximum air temperature of 33.7оC, while January had the lowest monthly maximum air temperature of -8.0оC as shown in Figure 5.2.

Figure 5.2: Maximum Air Temperature (оC)



Appendix 3-40

98. Minimum Monthly Air Temperature: In January 2005, the minimum monthly air temperature reached its lowest at -39.2оC, and in July, it reached 3.3оC.

Figure 5.3: Minimum Air Temperature (оC)


3. Precipitation

99. The average annual precipitation ranges from 249 to 261 mm. During the summer season there is 180-190 mm of precipitation and 75-80 percent of that falls in July and August. The winter has 5-7 mm of precipitation. It rains for 40-70 days and snows 25-30 for days each year, and there are about 140-170 days with snow coverage. The detailed precipitation in 2005 is shown per month in Table 5.2.

Table 5.2: Precipitations by Month (mm)

Months Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Total

Precipitation 1.9 2.3 2.5 7.1 20.6 35.6 61.9 63.7 33.2 7.1 5.7 3.3 242.5

Source: Institute of Meterology and Hydrology, 2005

100. In 2005, the total precipitation days were 56, and July has 11.1 days with precipitation, as shown in Figure 5.4. The daily maximum precipitation occurred in July, with 20.9 mm precipitation. The detailed maximum precipitation in each month is shown in Figure 5.5.

Figure 5.4: Number of Day’s for Precipitation (day)



Appendix 3-41

Figure 5.5: Daily Maximum Precipitation (mm)


4. Relative Humidity

101. During the spring from April to May, it is dry and windy, and the relative humidity is only 47% and 45% in April and May, respectively. The yearly average relative humidity is 62%. The detailed average monthly humidity is shown in Table 5.3.

Table 5.3: Relative Humidity (%)

Months Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Avarege

Relative Humidity 74 65 61 47 45 52 60 64 62 62 72 75 62

Source : Institute of Meterology and Hydrology,2005.

5. Wind Speed

102. In 2005, the yearly average wind speed was 2.5 m/s, and the April, May and June are the windy months. May is the windiest month when the average wind speed is as high as 4.0 m/s and the number of days with an even stronger wind is 9.8. However, in December and January, the two coldest months, the wind is weak and the wind speed is less than 1 m/s. The detailed wind speed and number of windy days are shown in Tables 5.4 and 5.5. Figure 5.6 shows the dominate wind directions in the different months. Annually, the dominate wind direction is from the north.

Table 5.4: Monthly Average Wind Speed (m/s)

Months Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Average

Wind Speed 0.8 1.3 2.6 3.9 4.0 3.7 3.1 2.8 2.8 2.3 1.5 0.9 2.5


Table 5.5: Number of Day with Strong Wind

Months Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec

Temperature 2 1.5 1.5 4.2 9.8 3.6 4.2 2.0 3.0 1.6 1.2 1.5



Appendix 3-42

Figure 5.6: Dominate Wind Direction of UB

Source : Institute of Meterology and Hydrology, 2005.

C. Water Resource

1. Water Resource in UB

103. Mongolia is arid and semi-arid country with annual average precipitation of 251 mm ranging from 400 mm in the north to less than 100 mm in the southern Gobi region. 90.1 per cent of which evaporates and only 9.9 per cent forms surface runoff. Of this remaining 9.9 per cent, 37 per cent infiltrates into the soil while 63 per cent turns into surface runoff. Almost 95 per cent of the surface runoff component flows out of the country. Consequently, only 6 per cent of Mongolia’s annual precipitation is transformed into available water resources in surface water bodies. Water resources of Mongolia are highly vulnerable to climatic conditions, are limited and unevenly distributed within the country. There are three main hydrological Basins: the Arctic Ocean, the Pacific Ocean and the Central Asian Endo-Archaic Basins. Rainfall is the principal source of water for the rivers of the region, while water from melting snow makes up 15-20 percent of the annual runoff. About two-thirds of the surface runoff leaves Mongolia.

104. The total water resource of Mongolia is estimated to be 609.6 km3. Twenty percent of all Mongolian water consumption originates from surface water sources and 80% originates from groundwater sources. Groundwater is currently the main source of supply for household and drinking use, watering points for pastures, and industrial consumption.

105. Water is not being recycled at this time; 70% of urban sewage is untreated. Domestic waste water in rural areas is mostly discharged into the environment without any treatment. The coverage of sanitation service is about 25%. Only 9.4% of water used by industries is recycled.

106. The study of water sources of UB began in the 1950s. In the 1993-1995 period the “Study on Water Supply System in UB and Surroundings” was conducted. It evaluated the development capacity of five water resources: the Upper, Central, Industrial, Meat Complex and Gachuurt were all examined. The most recent study was carried out in 2009 by JICA and known as the UB Water Supply Development Project in Gachuurt (see Table 5.6).

Jan, Still 72,3%

010203040

N

EN

E

ES

S

WS

W

WN

Frequency,%Speed/s

April, Still 36.6%.

0

10

20

30N

EN

E

ES

S

WS

W

WN

Frequency,% Speed/s

05

10 15 20 25 N

EN

E

ES

S

WS

W

WN

July, Still 39.5%

Frequency,%Speed/s

October, Still 55.8%

0102030

N

EN

E

EN

S

WS

W

WN

Frequency,% Speed/s


Appendix 3-43

Table 5.6 Water Resources in UB Area

№ Water Source

Potential Water Source*

Developed Water Amount in 1995*

Developed Water Amount in 2009*

Estimated Water Reserve **

(m3/day) (m3/day) (m3/day) (m3/day)

1. Upper 90,000 24,000 90,000Wells: 55 89,700

2. Central 114,300 97,000 110,000Wells: 93 114,000

3. Industrial 25,000 25,000 25,000Wells: 16 40,000

4. Meat Complex 15,000 15,000 15,000

Wells 11 22,000

5. Gachuurt 40,000 or less 0 0 -

6. Total 284,300 161,100 240,000Total № of Wells: 175 265,700

Source: * JICA1995MP & JICA Survey Team.

** According to official letter received from WA in July 29, 2009.

107. In 2010, the actual water production by USUG was 160,000 m3/day7. Excluding the Gachuurt reservoir, the estimated water surplus is 105,700 m3/day (265,700 m3/day - 160,000 m3/day) in the UB area. The Gachuurt reservoir of 60,000 m3/day of water rights is given to housing companies. The net balance is 45,700 m3/day. The new CHP5 water consumption is about 28,000 m3/day. From this view, we may conclude that there is enough water resource, if we exclude any city development.

108. In addition, water research studies around the confluences of the Ovor gorkhi (25-26 km upstream) and Terelj (60 km upstream) rivers were conducted. Their proven water reserves of the industrial category are 11,750 m3/day and 40062 m3/day, respectively. These reserves have not been touched or allocated yet.

109. Relevant information is not available from the recent ground water research study in airport area, just downstream of the meat complex, as a source of future industrial water needs.

110. The Tuul river flood plain in UB and Gachuurt areas was proclaimed as a water source protected area and sanitary zone of water supply under Ministry Ordinance No. 51/57 in March 2009 by the Ministry of Nature, Environment and Tourism on the basis of the Action Plan of UB City, 2009-2012. Only the development of domestic water is permitted, and there are no private wells or permanent structures in the area. 111. The rate of groundwater recharge or groundwater potential at the Gachuurt Water Source is set at 9% (Appendix 5) based on the cases of water balance at Zaisan Bridge at the south of the center of UB City and the water balance of Altai City.

2. Available Water Resource for CHP5

112. An available water resource for CHP5 can be found from the current CHP3 water source. Another source could be from the recently studied in airport area and according to the Water Authority material preparations are underway. It is estimated that the total water consumption of the CHP5 will be 8.1 million tons/year. The actual water consumption of the CHP3 is already about 9.0 million tons/year. 7 Source: USUG


Appendix 3-44

113. There are favorable hydro-geological conditions on the terrace of the Tuul River. The ground water level is at 1.5 m. Its existing water supply system, with a 41,300 m3/day reserve estimated before 70s, including 36,122 m3/day of Category A water and 31,097 m3/day of Category C2 water in 2007. Each day, 16,000 m3 of water is produced from this reserve.

114. CHP3 has 20 wells, 3 of which are not working, as shown in Table 5.7. During the winter, 7 wells will be used and only 4 wells will be used in summer leaving 10 wells in reserve, each of which has a yield of 36.8 liter/s. The total available flow rate of the wells was evaluated in 2007 and the amount was calculated to be 36,122.4 m3 per day (for 24 hours). The existing water supply system can be used for new CHP5 and there is no need to establish a new water supply system. The domestic water supply system is fed from city water utility.

Table 5.7: Wells Condition of CHP3

№ Well № Coordinates Depth(m)

Dynamic level (m)

Static level (m) Remarks

1 № 1 106˚47’45” 47˚53’48” 35.0 5.46 2.0 In working

condition

2 № 2 106˚47’32” 47˚53’53.5” 40.0 5.1 2.1 In working

condition

3 № 3 106˚47’19.1” 47˚53’57.8” 50.0 - 2.0 In working

condition

4 № 4 106˚47’4.5” 47˚53’2.0” 50.0 10.80 3.0 In working

condition

5 № 5 106˚46’46.5” 47˚54’5.5” 41.0 6.1 3.0 In working

condition

6 № 6 106˚46’46.5” 47˚34’8.43” 38.0 5.8 2.85 In working

condition

7 № 7 106˚46’25” 47˚54’11.0” 42.0 8.3 5.7 In working

condition

8 № 8 106˚46’9.17” 47˚54’10.37” 38.5 8.58 5.5 In working

condition

9 № 9 106˚45’45” 47˚53’48” 38.5 8.0 - In working

condition

10 № 10 106˚47’58.6” 47˚54’00” 50.0 - 5.0 Not working

11 № 11 106˚45’32” 47˚54’2.28” 50.0 6.05 4.22 In working

condition

12 № 12 106˚45’18.18” 47˚54’3.3” 50.0 5.72 5.0 In working

condition

13 №13 106˚45’2.8” 47˚54’2.56” 50.0 - 4.1 Not working

14 № 14 106˚44’39.1” 47˚54’1.52” 39.0 7.2 5.0 In working

condition

15 № 15 106˚44’15.24” 47˚53’59.7” 44.0 - 4.1 In working

condition

16 № 16 106˚44’6.0” 47˚43’20.41” 44.0 - 4.6 In working

condition

17 № 17 106˚43’54.08” 47˚54’12.86” 47.0 - 4.35 In working

condition

18 № 18 106˚43’36.6” 47˚54’13.3” 40.0 - 4.58 In working

condition

19 Well 1 at CHP3 fence

106˚52’5.5” 47˚55’54.5” - - 2.8 Not working

20 Well 2 at CHP3 fence

106˚53’51.6” 47˚52’5.4” - - 2.5 Not working

Source: CHP3.


Appendix 3-45

D. Geotechnical Conditions

115. Geologically stable, the foundation is made up of a thick alluvium deposit of quaternary age. No active faults have been observed. Earthquake magnitude of the CHP3 is 8. No permafrost is found on site. Seasonal freezing depth is 2.5 m. No any engineering geological phenomena and processes were observed in the CHP3 area.

1. Geology

116. The alluvium deposit in the Tuul River valley is wide spread even in the CHP3 area. On the top of this deposit there is a 0.2-1.7 m thick technogenic damped soil especially in the ash pond area. The alluvium deposit (aQIV) of quaternary age is mainly gravel, shingle and grits filled with sand. The alluvium deposit is 30-35 m thick and is 45-50 m thick in the water intake area. Underneath this deposit there is sand stone and slate formed in Carbonic age (C) of the Paleozoic period.

2. Morphology

117. The CHP3 and its ash pond area are located on the first terrace of the Tuul River. Its relief is generally flat, however because of construction activity there are many rubbish piles on top of the 0.2-1.7 m thick damped soil. In the small depressions formed between these piles ground water table can be seen on the surface. There is a lot of rubbish, especially in the ash pond area which hides the natural morphological elements. The southern part of the area is covered by young willow trees and grass lawn.

3. Hydrogeology

118. The main water bearing complexes or aquifers of the study area are as follows:

Aquifer of recent and upper quaternary loose deposit (aQIII-IV)

Aquifer of middle and upper quaternary loose deposit (aQII-III)

119. If we consider the hydro-geology of this area we note the water accumulated in this permeable alluvium deposit in the Tuul River valley. The thickness of this aquifer on average is 45-50 m. This water source is hydraulically connected to the Tuul River water. During low water periods Tuul River water feeds underground water and in high water period the process reverses. Underground water can be found at a depth of 0.5-4.0 m. The feeding zone coincides with the spread zone. Underground water level, yield and chemical composition vary annually or seasonally in connection with climate and surface water regime. Aquifer (aQIII-IV)

120. This deposit covers a large area in the Tuul River flood plain and all wells were established in this aquifer. The main water-bearing layer consists of boulder, gravel, shingle and sand with a thickness of 45-50 m, and in some place reaches 90 m. However the upper 25 m consists of a very permeable, well-rounded gravel and shingle containing abundant water in its porous areas. Below that depth as the clay component increases the water yield of the layer decreases. This water-bearing layer appears on average at a depth of 1.5 m, and wells in this layer yield 10-40 l/s, sometimes as much as 60-80 l/s water (according to PNIIIS study).

121. The permeability of this water-bearing layer varies from 50-200 m/day down to 30 m/day. This water-bearing layer is fed by underground infiltration from the Tuul River, precipitation and distant underground water infiltration from adjacent areas (see attachment-4).

122. The chemical composition of this aquifer belongs mainly to the type of sodium and potassium hydro-carbonate of type-1 and 2. Salt content 0.05-0.24 g/l, hardness is very low (see attachment № 1, 2007).


Appendix 3-46

Aquifer (aQII-III)

123. This aquifer is located in the II and III terraces formed above the flood plain of the Tuul River and consists of sand, gravel, shingle, sandy loam and loam. Its water-bearing capability is not constant. Yields from wells vary in a range of 0.9-24.0 l/s at a depth of 1.6-10.0 m. Chemical composition is potassium and sodium hydro-carbonate, sometime potassium-magnesium (PNIIIS study).

4. Engineering geology

124. The CHP3 area has many buildings and ash ponds. The open land between buildings, ash ponds and roads is covered by rubbish forming technogene soil mixed with natural soils. This technogene soil hides engineering geological phenomena and processes could be observed on the surface of that area. According to engineering and geological studies made in that area no engineering or geological phenomena were found around the CHP3 area.

125. In 1974, a Russian institute made an engineering and geological study round CHP3 drilling boreholes adjacent to the main facilities (main building, coal crasher, etc.) of the CHP3 and made 2 engineering and geological cross-sections (I---I, II---II). The average engineering and geological characteristics of all soil layers are shown in the table on the engineering and geological drawing above (see attachment-5). Please see the engineering and geological cross-sections or Appendix-1 translated from Russian into English. Unfortunately the map or drawing of the borehole locations could not be found in the archive of the CHP3 because some original drawings were sent to a consulting company during last rehabilitation project.

126. Additionally, in 2004 the “Inj Geotech” Co., Ltd made an engineering and geological study at one of the ash pond areas that was to be built about 200 m to the west of the CHP3. They sunk 6 boreholes to a depth of 10 m each. The drilling discovered a 0.2-1.7 m thick layer of top soil with plant roots here and there in some of the areas studied.

127. Two engineering geological elements (EGE) were discovered in the area, designated as EGE-1 and EGE2, which will be described as follows.

128. EGE-1. It is a brown-grey rubbish landfill dump soil consisting of gravel, construction waste filled with sand and sandy loam spread 0.2-1.7 m thick over the construction site. However this soil might not be used for foundation. Thus its engineering geological characteristics were not determined. 129. EGE-2. It is a brown-grey to brownish-yellow gravel and shingle soil filled with sand (aQIII-IV) . The moisture content of this soil varies from wet to saturated with water. This gravel and shingle soil filled with sand sometimes appears just under the dump soil and continued until a depth of 10 m.

130. Thirty samples from this soil layer were collected and sent to a lab for analysis. The average grain size result is shown below:

Gravel and shingle: 51.8% Sand: 36.5% Silt: 8.4% Clay:3.3%

Physical Parameters:

Natural moisture content : 0.062

Specific weight (g/cm2) : 2.67

Volume weight (g/cm2) : 2.13


Appendix 3-47

Skeleton volume weight (g/cm2): 2.14

Porosity (%) : 19.88

Porosity coefficient : 0.249

Moisture ratio : 0.67

131. Mechanical parameters determined according to SNiP-83 are as follows:

Cohesion force : CH = 2 kPa

Internal friction angle : φH = 43˚

Deformation module : EH = 50MPa

Angle of slope

- In dry condition : 42˚12’ - In wet condition : 36˚46’

Soil freezing depth : 3.8 m

Snow load on construction : 70 kg per each square meter.

132. Sand filled gravel and shingle soil does not swell. By hand work or machine work, the earth work is III grade.

133. Considering geology, geomorphology, engineering geology and hydro-geology the study area is designated as a medium engineering geological complexity area because its geology is simple, located on only one geo-morphological element, and ground surface is almost flat, and suitable for construction.

134. According to field measurements, the static water level in the boreholes drilled at the ash pond was 0.3-0.8 m, the permeability coefficient of the aquifer was 100-150 m/day and the water yield of the boreholes was 5.2-7.0 l/s .

135. While ground water does not directly damage concrete structures, it is capable of slightly corroding metal structures. The chemical composition of ground water in the ash pond area is high in sodium and potassium hydro-carbonate.

136. The earthquake potential is magnitude 8 according on Richter scale.

E. Conditions of the Ash Yard

137. The ash storage yard is situated 0.5 km west of the project site. It will be a dry ash yard. The storage capacity is approximately 1.5 million m3. If the ash can not be recycled or used as a construction material, the capacity of the ash yard can match the ash quantity accumulatively produced by CHP5 before 2024 and a new ash yard must be found for CHP5 after 2024. The ash storage area for CHP5 is shown in Figure 5.7.


Appendix 3-48

Figure 5.7: Ash Storage Area Map

Source: TA Team

F. Anti-disaster Ability Evaluation

1. Flood and Water Logging

138. The risk of flooding at the plant site of the Project is primarily from the peak discharge and flood level of the river near the plant site. Since the elevations of the plant area are all higher than the flood level from a 100-year flood event, it is not necessary to consider the flood’s impact. However, it is necessary to dispose of the foundation of the retainer wall in the plant area to prevent erosion. The primary mission of draining flooded fields in the plant area is to drain mountain torrents.

2. Main Power House and Chimney

139. Based on the International Aseismicity Design Directives and Provisions on Civil Works Structural Design Techniques of Thermal Power Plant and the grade 8 seismic fortification intensity of the proposed plant site, the anti-seismic calculation of all structures will be conducted in terms of Grade 8. The anti-seismic structure measures of the main power house, centralized control house, chimney, coal crusher room and transfer station, coal transporting corridor, cooling towers, and other important buildings are considered grade 9. The anti-seismic structure measures of general constructions will be considered in terms of grade 8.

3. Electric Installation

140. The 220kV circuit breaker of the Project is SF6 circuit breaker and can withstand an earthquake of grade 9, complying with anti-seismic requirements. Other electrical equipment of the Project shall be selected according to compliance with the requirement of withstanding an earthquake of grade 8.

141. The selection of electrical equipment for the Project has taken anti-seismic requirements into account and is earthquake disaster resistant.

142. The plant site of the Project has infrequent dust storms. All outdoor electric installations shall be selected according to the requirements that protection level is not lower than IP54 and leakage distance is not less than 25 mm/kV. This is designed to have relatively


Appendix 3-49

strong ability to resist sand dust.

4. Extreme Low Outdoor Temperature, Thunder and Lightning

143. The project is to be situated in UB, located at east longitude of 106° 53’ and north latitude of 47° 55’. The mean annual precipitation ranges from 249 to 261 mm. The winter is bitter cold. The extreme minimum air temperature is -47°C. The maximum snow load is 70kg/m2 and the maximum depth of frozen ground 3.8m.

144. Based on past experience, thunderstorm disasters can be averted by comprehensive lightning protection measures, including combining lightning conductor and strap type lightning protector to prevent direct lightning flash and lightning protection electric wave with installation of lightning arrester and reinforcing ground connection to meet the Project’s lightning protection requirements..

5. Protect Against Severe Snow

145. According to the international design practices, the structural design will consider the aforementioned snow pressure parameters.

6. Frost Prevention

146. The water-cooling systems already in operation have experienced freezing prevention issues. Water-cooling companies worldwide have successfully carried out in-depth studies of the many aspects of preventing freezing regarding the application of water-cooling system to cold, bitter cold, or alpine regions. The extreme minimum air temperature of the Project is -47 °C. In similar areas and under similar environmental conditions, there are many engineering projects that have been put into operation and are being constructed.

147. The outdoor primary switches will be equipped with prevention measures against SF6 gas liquefaction. Other outdoor equipment shall comply with requirement of minimum air temperature of -47 °C. In addition, according to cable design specifications, under cryogenic environment below -15 °C, chloral PVC-insulation or PVC sheath cable is not suitable for use. Therefore, part of the outdoor cable for the Project will employ cross-linked polyethylene insulation, insulating ethylene sheath cable or polyethylene insulation, and insulating ethylene sheath cable, if possible.

7. Conclusion of Counter-Disaster Evaluation

148. In the process of selection of plant site and layout plan, the regional crustal stability and site stability of plant site have been considered adequately. The construction site is at a regional crust stable block, away from regional active fault zone, and it is not likely to suffer from major landslide, collapse, mudslide, surface collapse, and other geological disasters, as well as unfavorable geological functions. This location can guarantee geo-stability and the safety of the plant site.

149. The Project will be designed according to international practices and power plant design criteria rules and specifications. Relevant design criteria and alternate design principles meet corresponding counter-disaster requirements of power plants construction.


Appendix 3-50

VI. CONCEPTUAL DESIGN FOR THE CHP5 PLANT

A. Installed Capacity and Key Indicators of CHP5

1. Technical Principles CHP

a. Rationale of Application of CHP Technology

150. Coal-fired power plants dedicated to electric power generation and using the latest commercially available advanced technologies can generally reach an overall net efficiency of approximately 40%. Significant amounts of energy released by coal combustion are lost during the steam condensation segment of the Rankine cycle due to heat transfer into the cooling water. However, the CHP facilities, also known as cogeneration facilities, could allow recovery of some of the heat that would otherwise be rejected into cooling water and improving the overall energy utilization efficiency as high as 50~80%.

b. Strategy of “Power Determined by Heat” 151. Extensive studies and investigations conducted by the TA team have indicated that in addition to its technical, environmental, financial, and economic benefits, application of CHP in UB will be significantly advantageous due to its inherent eight-month long heating season and stable heat and hot water demand. A reliable heating service is not merely a utility for citizens of UB, it is indeed a matter of life and death in such a climate. Therefore, a safe, clean, and reliable heating supply is a critical need for the entire population of Mongolia. The principal of “Power Generation Determined by Heating Supply” will be fully followed in engineering the installed capacities and selection of turbines for the proposed CHP5 plant.

c. Principals of Designing a CHP Plant 152. A CHP plant shall be designed according to a city master plan, urban district heating plan and cogeneration plan to specify planned capacity, construction schedule, and operational arrangement. The “Triple Simultaneous Principal” shall be strictly followed to construct a functioning CHP plant and associated urban heating network: that is, simultaneous engineering design, construction, and operation. A cogeneration plan shall be developed to comply with principal of “integrated planning, phased implementation, power supply determined by heating load, and reasonably sized capacities”. The installed capacity and units of the proposed CHP plant shall then be designed to fit the heating loads and power grid capacity of UB.

153. International specifications and proven practices suggest that a CHP plant with a stable heating load (daily load fluctuation rate of 10%~20%) should install a back pressure or extraction steam back pressure turbine unit, so as to reduce investment cost, save energy consumption, and gain better economic benefits.

154. A CHP plant with an unstable heating load should install a combined unit of an extraction-condensing steam turbine and back pressure or extraction steam back pressure systems.

155. A CHP plant with a higher heating load fluctuation rate should install an extraction condensing steam turbine, however the overall yearly average heating efficiency shall be greater than 45% and yearly average heat-power ratio shall be greater than 50% (for a single unit capacity of 50, 100 and 125 MW).

156. A plant located at a coal mine mouth, burning low rank coals, should install a smaller condensing steam turbine.

157. Initial parameters of a new turbine unit should be defined according to the following:

Single unit capacity of 1.5 MW - sub-medium or medium pressure parameter;

Single unit capacity of 3 MW - medium pressure parameter


Appendix 3-51

Single unit capacity of 6 MW, 12 MW - sub-high pressure parameter

Single unit capacity of 25~100 MW - high pressure parameter

Single unit capacity of 100 MW - super high pressure

Unit capacity > 300 MW –subcritical pressure or supercritical pressure

The initial design parameters for a CHP plant extension should be justified to be the same as those designed for the original unit, or for a new turbine unit.

158. Boilers should be selected based on total heating capacity, total power generation capacity, technical performance, type of available coals, commercial availability, O&M performance, and capital investment, etc. A detailed comparative analysis of boiler selection is described later.

159. The turbine capacity shall be compatible with the boiler capacity to meet specified requirements under various heating load conditions. Verifications shall be made to ensure that the total inlet steam is not lower than the minimum stable combustion loads without fuels being fed under the minimum heating load condition so as to ensure a safe, stable and cost-effective operation of the boiler. The condensing inlet steam shall be designed to ensure a safe and stable operation under minimum condensing conditions.

160. The total quantity of boilers, their sizes and capacities shall be calculated to ensure a continuous industrial steam supply, if any is required, as well as to provide 60~75% of the total residential hot water supply during winter season (75% in Mongolian case), even in the cases in which the biggest boiler is not in service, all other boilers including peak load boilers and standby boilers could immediately take over to provide the required heat.

2. Installed Capacity of the CHP5

161. Based on the heating demand and power demand forecast and to follow the principal of “Power Generation Determined by Heat Supply”, 5 x 150 MW steam extracting turbines, plus (1) x 70 MW back-pressure turbines are envisioned. Based on the detailed calculations, the maximum heating capacity of the six (6) turbines will be 1281MW (1101Gcal/hr) and the power generation of the six (6) turbines will be 820 MW, under the maximum heating capacity. The project is planned to be implemented in two phases. During phase I, three x 150 MW steam extracting turbines, with total 587 MWt (505 Gcal/hr) heating capacity, are envisioned. During Phase II, an additional two x 150 MW steam extracting turbines and (1) x 70 MW back-pressure turbines will be installed, with total 1,281 MWt (1,101Gcal/hr) heating capacity.

3. Key Indicators of the CHP5

162. In accordance with the installed heat and power generation capacity, heat demand, and related working parameters of key equipments, the key indicators of the CHP5 are shown in the Table 6-1.


Appendix 3-52

Table 6.1: Key Indicators of the CHP5

Items Unit Total Project

Installed Power Generation Capacity MW 820

Installed Heat Supply Capacity MWt 1,281

Gcal/hr 1,101

Heat demand MWt 1,281

Gcal/hr 1,101

Yearly Power Generation million kWh 4,100

Internal consumption million kWh 410

Transmission Loss million kWh 41

Net Power Supply million kWh 3,690

Internal heat consumption million GJ 0.2

million Gcal 0.05

Yearly Net Heat supply million GJ 12.5

million Gcal 3.0

Average Annual Ratio of Heat to Power 0.84

Efficiency

Power Generation % 46.7

Heat Generation % 89

Total Thermal efficiency % 59.7

Fuel consumption

Standard Coal Consumption Per kWh g/kWh 263

Standard Coal Consumption Per GJ kg/GJ 38.3

Stand Coal Consumption million tce 1.56

Baganuur million ton (raw) 0.99

Shivee-Ovoo million ton (raw) 2.63

Raw Coal or LPG million ton (raw) 3.62

Note: The yearly working hours of CHP2, 3 & 4 were about 4000 hours to 4500 hours in last five years. Considering the economic development and power demand increase, power generators of CHP5 are expected to be working 5000 hours, which is the base for calculation of yearly power production.

B. The Plant Site

1. General External Condition of the Entire Plant

163. Water supply system. Treated groundwater will be used for make-up water and a separate water circulation cooling system will be built for the Project.

Fuel transportation system. The railway is accessible to the power plant. The dedicated lines start at the station and arrive at the plant area from the northeast direction. The internal line should be improved to meet the increased transportation capacity. 164. Ash yard. The ash yard will be located at the west side of the main plant, about 0.5 km away from the plant. When ash pile reaches a height of 11 m high, that storage volume will


Appendix 3-53

equal up to 1.5 million m3, occupying total land area of 13.6 ha. The storage capacity of the ash yard will meet the ash volume before 2024.

165. Outgoing lines. Currently, 110kV and 35kV voltage power supply system is used. The 220kV power distribution unit will be installed in the plant. 166. Heat supply pipeline. The power plant will supply most of the heat to customers residing in central and eastern areas of UB, where the new route begins at the industrial district area, via the 5A Primary Pipeline, the Energy Authority building, Dundgol River Dam, Peace Bridge, then returns back to Sun Road and ends at the Narantuul Market, where it finally connects to the existing pipelines.

167. Access road. The Project is accessible to roads however some of the existing roads need rehabilitation. The access road to ash pond should be constructed from the west side of the plant site up to the ash pond. The total length of the new road is about 0.5 km.

168. Tentative Construction Yard. The construction yard is tentatively built within the plant area, covering total land area of 3.0 ha.

2. New Site Arrangement for the CHP5

169. The CHP5 is proposed to be constructed in two phases at the location within the existing grounds of the CHP3, where the CHP3 high-pressure system is to be maintained and its low-pressure system will be removed off the site. The high-pressure system is located in the site center and the low-pressure system in on the eastern side of the complex. The low-pressure system is to be decommissioned once its heating capacity is taken over by the new plant. Obviously there are challenges in achieving the best layout of the new CHP5. The proposed arrangement of the new plant area could make full use of the existing land area and minimize the impacts brought about by the construction of the CHP5 on the normal operation of the existing CHP3.

170. As the high-pressure system is proposed to be situated in the center of the CHP3, the CHP5 is to be constructed on both sides of the high-pressure system. There are two options: Option 1 is to locate Phase I of CHP5 on the east side of the CHP3 high-pressure system and Phase II on the west side of the high-pressure system; and, Option 2 is to locate Phase I on the west side of the CHP3 high-pressure system and Phase II on the east side. It is suggested that the construction activities be well planned and organized to ensure normal operation of CHP3’s high-pressure system for a stable and continuous heating and power supply for the existing customers. Option 1: Phase I Located on the East Side (i) General Layout

171. The general layout of the plant area employs a triple-array arrangement form. The coal bunker and deaerator house, the boiler house, the turbine and generator house, the outdoor power switchyard and the water cooling towers are located successively from southwest to northeast. The ESP and auxiliaries will be installed at the southeast side of the boiler house.

172. Within the main plant area, the units or facilities are installed successively from northwest to southeast: steam engine house → deaerator and coal silo house → boiler house → blowing fans →ESP → induced fans → chimney. A bottom ash bunker is installed alongside of each boiler.

173. Auxiliary operations and services will be installed around the main plant from the northeast to the southeast: the office and administration complex, the chemical water workshop, the industrial wastewater treatment workshop, the service water pumps house, the fire protection and domestic water facility, the domestic wastewater facility, the materials depot, and the lime treatment workshop will be located between the main plant and coal yard. The hydrogen storage station, oil tank farm, mechanical workshop and ash bunkers are


Appendix 3-54

located on the west side of the main plant.

174. Due to limited space available for Phase I, the two water-cooling towers and the circulating pump house for Phase I need to be located in the northwest corner of the new plant site and one water-cooling tower and circulating pump house for Phase II needs to be located in the northeast corner of the new plant site, Such a site arrangement would require a longer circulating cooling water pipeline and consume more pump motor electricity, and therefore is not technically Justified.

175. The 220kV switch yard proposed for Phase I is to occupy the space currently used by the existing switch yard of the low-pressure system. The space currently used by the existing spraying cooling pool can be used for the switch yard proposed for Phase II, in northwest side of the main power house. The 110kV switch yard of the high pressure part is to be located between the two new 220kV switch yards. To connect the 220kV overhead transmission lines of UB, the 220kV transmission lines proposed for Phase I need to be supported by a higher tower for an adequate height passing across the 110kV lines used by the high pressure switch yard. There are challenges for such an installation and therefore it is a costly option.

176. The main entrance and exit of the power plant are at the northeast side of the plant area. The transport entrance and exit for ash, residue, and fuel are at the northwest side of the main power house, linking the access road and ash transport road, respectively.

(ii) Construction Sequence

177. Construction for Phase I involves relocating the office, low-pressure system decommissioning, and construction of the new facilities requiring minimizing impacts to the daily operations of CHP3 to ensure a stable and continuous heat and power supply.

178. First, the existing office has to be removed off its original location to make room for the first boiler and its heat exchangers to be used for district heating to take over the heating capacity of the low-pressure part of CHP3. The 35kV substation is to be relocated to the north of the 110kV switchyard to ensure a stable and continuous power supply to the existing customers.

179. Once the first boiler is put into service, the low-pressure section and its auxiliary facilities can be completely dismantled. On the old site of the low-pressure section, the remaining two boilers and turbines, generators and other equipments and facilities for Phase I of CHP5 can then be installed. At the same time the switch yard for Phase I is to be installed at the east side of the switch yard used by the high-pressure section of CHP3. In addition, the other two cooling towers are to be constructed on the northwest corner of the site. Civil engineering work for the water treatment facilities, the wastewater treatment facilities, and other auxiliary services will be completed during Phase I. The related equipment can be installed in phases.

180. The coal yard for the high-pressure section will be shared by Phase I. The existing coal yard needs to be upgraded to provide adequate coal storage and handling capacity. One new bucket wheel stacker and reclaimer will be installed, and other auxiliary coal conveying system components will be constructed and installed. Coal is transported from the coal yard on a belt conveyor, through transfer stations to the coal crusher room at the fixed end of main power house, then fed to the coal bunkers for each boiler. Under Phase II, the coal yard is to be extended further west, and the storage capacity of the coal yard is to be increased to meet the demand of both Phase I and Phase II, during which, the coal yard area will be extended further to the west. More equipment will be added including one bucket wheel stacker and reclaimer and related auxiliary equipment. The coal for Phase II will be transported by another conveying system on the west side.


Appendix 3-55

Option 2: Phase I Located on the West Side (i) General Layout

181. Under this option, the general layout of the plant area is similar to Option 1. It also adopts triple-array arrangement form. The auxiliary operations facilities are installed around the main plant.

182. Two water-cooling towers and a circulating pump house for Phase I will be installed in the northwest corner of the project site, and one water-cooling tower and circulating pump house for Phase II will be installed on the northeast corner of the site. Thus, the cooling towers for both phases are installed close to the main plants of Phase I and Phase II. This is technically justifiable.

183. The 220kV switch yard proposed for Phase I will occupy the space currently used by the existing spray cooling pool. The space currently used by the existing switch yard of the low-pressure section will be used by the switch yard of Phase II. The 220kV transmission lines proposed for Phase I can be easily connected to the 220kV overhead transmission lines of UB with no need to cross over the 110kV lines. For Phase II, the 220kV lines can be connected to the 220kV switch yard internally.

184. The main entrance and exit of the power plant are at the northeast side of the plant area. The transport entrance and exit for ash, residue, and fuel are at the northwest side of the main power house, linking respectively the access road and ash transport road. (ii) Construction Sequence

185. Construction of Phase I will not require relocation of the office, but only the decommissioning of low-pressure section, and construction of new facilities without impacts on the normal heat and power supply.

186. The spray cooling pool of the low pressure system will be dismantled, while the boilers of low pressure system will be remained. Meanwhile, electricity of LP can be easily covered by other sources, and it is allowed for low pressure system not to generate electricity. Therefore, we proposed that the low pressure system will only generate steam for heating, and not generate electricity before CHP5 is put into service. In this case, the steam from low pressure system boilers will directly go to the heating exchangers for heating up the hot water for district heating system and industry customers through reducers and not go to turbine for power generation. The spray cooling pool is not required for this operating scenario. The site of the spray-cooling pool will be used for switch yard for Phase I. The 35kV substation will be relocated to the north of the 110kV switchyard to ensure power supply for the existing customers.

187. The main plant of Phase I can be constructed easily as it is to be located in an open area on the west side. The switch yard can be constructed on the site of the existing spray-cooling pool. The civil engineering work for the water treatment facilities, the wastewater treatment facilities, and other auxiliary services will be completed during Phase I. The related equipment can be installed in phases.

188. The proposed Phase I coal yard will be constructed on the area close to the existing coal yard. Additional systems and facilities are to be installed, this includes one new bucket wheel stacker and reclaimer and auxiliary facilities for the coal conveying system. The coal is transported from the coal yard, through the belt conveyor, transfer stations, and coal crusher room, the fixed end of main power house, then fed to the coal bunkers of each boiler. Under Phase II, the coal yard is to be extended further east, and the storage capacity of the coal yard needs to be increased to meet the demand of both Phase I and Phase II. The existing coal yard for the CHP3 is to be upgraded and one additional bucket wheel stacker and reclaimer and related auxiliary equipments are to be installed. Coal for Phase II will be transported by other conveying system in the west side.


Appendix 3-56

189. Once Phase I is put into service, the low-pressure system and its auxiliary facilities can be fully decommissioned and the remaining two boilers and turbines, generators and other equipments and facilities will be installed on the site previously occupied by the low-pressure system. At the same time the switch yard proposed for Phase I will be installed at the east side of the switch yard of the high-pressure system. In addition, one cooling tower is to be constructed on the northwest corner of the site.

Conclusion 190. In general, both options are technically feasible. However, Option 2 is comparatively preferred having three major advantages over Option 1:

191. First, construction of the CHP5 will make relatively minor impacts on the normal operation of the existing facilities and provides more flexibility for smooth transition from the old production into new one, primarily due to the fact that it does not require actions to decommission the low-pressure system and relocation of office in advance.

192. Second, the two cooling towers have to be located on the west side, and another one in northeast corner. Phase I requires two cooling towers, while Phase II requires one cooling tower. Therefore, Option 2 allows Phase I to be closer to the two cooling towers, and Phase II closer to another cooling tower, which is technically more reasonable.

193. Third, the 220kV overhead transmission lines can be readily connected to the urban 220kV grid, which reduces the cost and level of construction difficulties.

194. In conclusion, Option 2 is recommended for the Project. Under Option 2, total land area within the wall boundary of the plant area is 47.5 ha (2.5 ha to be acquired). The site layout is shown in Drawing TA7502-MON-Z02.

3. Technical Indicators

195. The technical indicators in relation to the general layout of the main CHP5 plant are summarized in Table 6.2.

Table 6.2: General Lay-out Index of the Plant Area

No. Description of Indicator Unit Indicator Value

1 The land area ha 47.5

2 Land area of unit capacity m²/kW 0.6

3 Land area occupied by buildings and structures in plant site ha 16.65

4 Building Index % 37

5 Road and square surface m² 4.5

6 Road square coefficient % 10

7 Area for forestation in the plant area ha 6.3

8 Ratio of green space in the plant area % 14

9 Enclosing wall length of the plant area m 3515

4. Vertical Planning of the Plant Area

196. Topographically, the land to be used for the plant area is relatively flat and open. Considering factors in relation to the flood control level and the railway alignment, the vertical arrangement represents a step type pattern. Surface water within the plant area drains in a well organized pattern: storm water is collected by catchments on the roads and flows to a storm water pump house via storm water sewers, where it is pumped to the municipal sewage system. Surface water within the coal yard is collected by ditches around the coal yard,


Appendix 3-57

flows to the sedimentation tank, and is discharged off-site after treatment to comply with the applicable discharge standards.

C. Main Equipment Selection

1. Turbine Selection

197. The turbine capacity shall be compatible with boiler capacity to meet specified requirements under various heating load conditions. Verifications shall be made to ensure that the total inlet steam is not lower than the minimum stable combustion loads without fuels being fed under the minimum heating load condition so as to ensure a safe, stable and cost-effective operation of the boiler. The condensing inlet steam shall be designed to ensure a safe and stable operation under minimum condensing conditions.

198. Key Factors for Identification of the Best Scheme. The heating load shall be carefully calculated and verified for establishing a baseline to design a reasonable sized CHP plant. The verified heating load shall serve as a basis for design of CHP plant and heating networks. The best scheme shall be identified to ensure the best social, environmental and economic benefits, including for example, total heating efficiency of over 45% for conventional coal-fired CHP plant; and heat power ratio of over 50% for a single turbine unit capacity of 50, 100, and 125 MW. Alternative turbine units shall be carefully studied and compared to evaluate their heat economic performances and steam balance diagrams. The heating supply options shall be designed for optimization including heating networks. Alternative boilers shall be well justified in consideration of available ranks of coals, heating load characteristics, slag utilization, and environmental protection. Detailed calculations shall also be made with regard to the heating mediums, heating supply parameters, peak load boiler operation, standby boiler arrangement, as well as the reliability of heating supply, etc. once the turbine system is designed. 199. Alternative Heating Turbines. A heating turbine has two functions of heating supply and power generation. It has three major categories: back pressure (complete back pressure or extraction steam back pressure); regulating extraction steam (one-time regulating and two-time regulating); and, condensing steam-heating turbine. A back pressure turbine uses outlet steam after expansion for heating supply. An extraction condensing turbine extracts expanded steam from an intermediate stage of the turbine for heating supply by reducing outlet steam entering the condenser. The extraction condensing turbine extracts one part or two parts of the steam for heating supply and the rest of steam returns back for reheat and work. A condensing-heating turbine installs a butterfly valve on a connecting pipe of medium-pressure to low-pressure cylinders, providing heat by reducing power generation during heating season and serving as a condensing turbine during non-heating season. 200. A back pressure turbine is designed to use all outlet steam for heating supply purpose. The outlet steam is no longer a energy loss. A back pressure turbine operates in line with “Power Determined by Heat” approach, where both power generation and heat supply are not able to be regulated separately and the back pressure turbine could not operate independently without heating load. An increased heating load could only be reached through generating more steams and at the same time generating more power. As a result a standby grid capacity is to be expanded or reserved. Figure 6.1 illustrates a simplified schematic of back pressure turbine operation.


Appendix 3-58

Figure 6.1: Simplified Schematic of Back Pressure Turbine

Source: Cogeneration Design and Operation Manual

201. An extraction condensing turbine without steam reheating is designed to meet simultaneously both variable heating loads and variable power generation demands. Steam is extracted from one of the stages for heating supply and returns back after cooling down at end users to the boiler for recirculation. An increased heating load could be reached through generating more steam, which subsequently increases the power load. To maintain a constant power load, the inlet steam entering low-pressure cylinder is regulated through medium-pressure regulation valve to reduce low-pressure cylinder load. Whereas a load increase at the high-pressure cylinder dose not contribute to total power generation variations thus reaching a new balance of heat and power loads. The variable heating loads could be managed by regulating the steam extracted and the inlet steam entering turbine so as to maintain constant power generation. Figure 6.2 shows a simplified diagram for an extraction steam turbine system without a steam re-heater. The international least-cost practices suggest that turbines without steam re-heater could only provide capacities lower than 100 MW and pressures lower than 10MPa. There is a limited number of manufacturers who can fabricate this kind of turbine with capacities of greater than 100MW and pressure greater than10MPa.

Figure 6.2: Simplified Systematic of Extraction Condensing Turbine



Appendix 3-59

202. A condensing-heating turbine installs a butterfly valve on a connecting pipe of medium-pressure to low-pressure cylinders, providing heat by reducing power generation during heating season and serving as a condensing turbine during non-heating season. Its steam flow at the high-pressure cylinder is calculated based on the condensing flow. When steam is extracted for heating supply, the power is resultantly decreased. The extraction steam operation has similar characteristics of extraction steam turbine. It is one of the effective options in cogeneration industry due to its simplicity of designs and lower capital cost. Figure 6.3 is a simplified systematic for a condensing-heating turbine with a steam re-heater. This kind of turbine design allows a capacity greater than 150MW and pressure greater than 13MPa, which provides relatively higher efficiency. Worldwide, steam turbines equipped with a steam re-heater are currently quite popular. However the installation of a steam re-heater would not allow the use of the common header, which leaves no backup boiler for the system. More reliable and technically-proven products are needed to address this issue.

Figure 6.3: Simplified Systematic of Condensing-Heating Turbine


a. Comparative Analysis of Alternative Turbines 203. A back pressure turbine is designed to provide steam for heating supply under defined outlet steam parameters and at the same time to provide certain amount of power. No condensers are required and therefore no cooling losses are generated. It is an economically viable option. However it could not able to satisfy both heating supply and power generation requirements at the same time. A back pressure turbine adheres to “Power Determined by Heat” principal, where power load variations are managed by other parallel grid units. In addition, inadequate steam is obtained through a boiler temperature and pressure reduction as to make up the heating loads required, which results a decrease of the overall economic performance of the CHP plant. 204. An extraction condensing turbine (one-time regulating, for example) extracts part of the expanded steam for heating supply and continues working and expanding and finally exhausts steams into the condenser. It combines both the operational functions of a back pressure turbine and a condensing turbine and could meet both heating supply and power generation requirements at the same time. An extraction condensing turbine with two-time regulating is such a design which combines two back pressure turbines and one condensing turbine in series. 205. In meeting the specific requirements of the Project, turbine capacity is to be designed no more than 150 MW. The Project’s goal is to design the CHP5 as a demonstration model using the advanced technology for Mongolian power sector. The advanced technology applied at the CHP5 should best fit the requirements of both power and heating supply systems. Technically, a 150MW turbine with a steam re-heater is more advanced than the


Appendix 3-60

100 MW or higher turbines without steam re-heater. Typically, a 150 MW turbine is designed with a steam reheating system, which generates higher efficiency. There is a limited number of manufacturers who could manufacture turbines at 150 MW or higher capacity and without steam reheating system. Currently, steam turbines equipped with steam re-heater is quite popular worldwide. However, the installation of a steam re-heater, would not allow the use of common header, which therefore provides no backup boiler for the boiler system. More reliable and technically-proven products are needed and additional units are to be installed to handle issues due to outages of certain units.

b. A Good Combination of Featured Turbines 206. As described above, different turbines have different characteristics. The back pressure turbine is an ideal solution of choice for the proposed CHP plant with regard to its heating supply advantages as well as its better economic performance. The extraction condensing turbine with multi-level regulations provides services of both heating supply and power generation. It is one of the best technical combinations to not only meet heat supply and power generation requirements but to offer wide range of flexibilities to satisfy variety of process needs. It is therefore recommended for application in the proposed CHP plant as a major integral part of the turbine arrangement.

c. Technical Calculations 207. According to international practices, for one-time regulating extraction steam turbine, the design steam flow in the high-pressure cylinder shall be 1.2 times of the total inlet steam flow under rated power and rated extraction steam. For two-time regulating extraction steam turbine, the design steam flow in the medium-pressure cylinder shall be 70~90% of the total inlet steam flow under the conditions that the rated power and rated industrial extraction steam flow are zero and that the steam for heating supply is at its highest level. One-time regulation extraction steam pressure shall be designed at its lowest level, provided that the pressure shall meet the heating supply requirement. Thus, an increased ideal enthalpy drop could be reached as a result of increased power generation and improved economic performance. Normally, when industrial extraction pressure is decreased from 1~1.2MPa to 0.6~0.7MPa and heating supply pressure from 0.12~0.25MPa to 0.05~0.25MPa, the economic performance of the unit could be greatly improved.

208. International practices suggest that the capacity of a single power generation turbine shall not be over 15% of the total power generation capacity, preferably, lower than 10%, so as to minimize adverse impact on the entire power supply system with regard to its safety, reliability and stability. In addition, considering the fact that the CHP5 is to be constructed in phases, it is critical to ensure the reliability of heating supply. If the capacity of each unit is increased, the total quantities of turbines must be decreased, as a result the reliability of the heating supply is compromised. The capacity of the power generation shall be designed to consider the fact that the total installed power generation capacity of the existing CES is only 814 MW and that the CHP5 is mainly designed to meet the heat demands. As the total capacity of the CHP5 is expected to reach 820MW, the 150 MW capacity of each turbine is technically appropriate to meet the requested capacity of the CHP5.

209. International practices indicate that a super high pressure system will adopt a steam reheating cycle to increase its power generation efficiency, which will require a module configuration between boilers, turbines, and generators. Thus, a common header cannot be used in the primary steam system, as a result no backup boiler is provided for the boiler system. Further, due to the eight-month long heating season, a back pressure turbine is one of the best solutions for this project. Application of a back pressure turbine, with 85% higher thermal efficiency, will greatly improve the thermal efficiency of the entire plant. The district heating system practices indicate that a well-designed back-pressure turbine of 0.4 MPa will improve both the financial viability and thermal efficiency. The back-pressure turbine will be operated during the entire heating season to maximize the energy efficiency. If the heating


Appendix 3-61

demand is higher than the heating capacity provided by the back-pressure turbine, the extraction condensing turbines will provide the required heating services.

210. Based on the heating demand and power demand forecast, following the principal of “Power Generation Determined by Heat Supply”, 5 x 150 MW steam-extraction turbines, plus one 70 MW back-pressure turbine are tentatively planned. The thermodynamics diagrams for the extraction-condensing turbine and back-pressure turbine are shown in Draining TA7502-MON-J01. Under rated steam-extraction volume, the steam-extraction turbine will generate 135MW power capacity and 280 ton/hr of steam extracting capacity. The back-pressure turbine will generate an exhausting steam capacity of 345 ton/hr. Under the maximum heating capacity, the maximum heating capacity of six (6) turbines is calculated at 1,281MW and the power generation of six (6) turbines is calculated at 745 MW. During phase I, three x 150 MW steam extracting turbines, with a total of 587 MW heating capacity, are planned. During Phase II, and additional 2 x 150 MW steam extracting turbines and 1 x 70 MW back-pressure turbine, with a total of 694 MW heating capacity, are planned.

2. Boiler Selection

211. The total number of boilers, their sizes and capacities shall be calculated to ensure a continuous industry steam supply, if any is required, as well as much as 60~75% of the total residential hot water supply during winter season (75% in Mongolian case), even in the instances when the largest boiler is not in service, all other boilers including peak load boilers and standby boilers could immediately take over to provide the required heat.

a. CHP Facilities Using Coal 212. An industrial boiler is typically defined by its common function – a boiler that provides heat in the form of hot water or steam for various defined applications. Industrial boilers can use a number of different fuels including coal (bituminous, sub bituminous, anthracite, lignite), fuel oil, natural gas, biomass (wood residue, sugar cane residue, etc.), liquefied petroleum gas, and a variety of process gases and waste materials.

213. Statistic studies show that in 2008, approximately 70% of the electricity used in the United States was generated by burning fossil fuels (coal, natural gas, petroleum liquids). The combustion of a fossil fuel to generate electricity and heat can be either: i) in a steam generating unit (also referred to simply as a “boiler”) to feed a steam turbine that, in turn, spin an electric generator; or ii) in a combustion turbine or a reciprocating internal combustion engine that directly drives the generator.

214. Some modern power plants in the world use a “combined cycle” electric power generation process, in which a gaseous or liquid fuel is burned in a combustion turbine that both drives electrical generators and provides heat to produce steam in a heat recovery steam generator. The steam produced by the heat recovery steam generator is then fed to a steam turbine that drives a second electric generator. The combination of using the energy released by burning a fuel to drive both a combustion turbine generator set and a steam turbine generator significantly increases the overall efficiency of the electrical power generation process.

215. Coal is the most abundant fossil in many countries in the world and is predominately used for electric power generation and heating supply. Historically, electric utilities have burned solid coal in steam generating units. However coal can also be first gasified and then burned as a gaseous fuel. The integration of coal gasification technologies with the combined cycle electric generation process is called an integrated gasification combined cycle (IGCC) system or a “coal gasification facility”.

216. Under the American Society for Testing and Materials (ASTM) method D-388, coals are divided into four major categories called “ranks”: anthracite, bituminous coal, sub-bituminous coal, and lignite. Typical coal characteristics for the three most commonly used coal ranks are summarized in Table 6.3 below.


Appendix 3-62

Table 6.3: Selected Characteristics of Major Coal Ranks

Coal Rank Higher Heating Value Range Defined by ASTM

D-388

Typical Coal Moisture Content

Average Ash Content

Average Sulfur Content

Bituminous >10,500 Btu/lb 2~16% 10.6% 1.68%

Sub-bituminous 8,300 - 10,500 Btu/lb 15~30% 5.8% 0.34%

Lignite < 8,300 Btu/lb 25~40% 13.8% 0.86%

Source: USEPA.

b. Coal Utilization in CHP Facilities 217. The steam is produced by the boiler, where water pumped into the boiler (“feedwater”) passes through a series of tubes to capture heat released by coal combustion and then boils under high pressure to become superheated steam. The superheated steam leaving the boiler then enters the steam turbine throttle, where it powers the turbine and connected generator to make electricity and provide heat.

218. After the steam expands through the turbine, it exits the back end of the turbine into the surface condenser, where it is cooled and condensed back to water. This condensate is then returned to the boiler through high-pressure feed pumps for reuse. Heat from the condensing steam is normally rejected to cooling water circulated through the condenser which then goes to a surface water body, such as a river, or to an on-site cooing tower.

219. A power plant can be classified as either dry or wet bottom, depending on the ash removal technique used. Dry bottom boilers fire coals with high ash fusion temperatures, allowing for solid ash removal. In the less common wet bottom (slag tap) boilers, coal with a low ash fusion temperature is fired, and molten ash is drained from the bottom of the boiler.

220. To improve the overall thermal conversion efficiency, the majority of power plants include a series of heat recovery sections. These sections are located downstream from the furnace chamber and are used to extract additional heat from the flue gas. The first section contains a “superheater”, which is used to increase the steam temperature. The second heat recovery section contains a “reheater”, which reheats the steam exhausted from the first stage of the steam turbine. This steam is then returned for another pass through a second stage of the turbine. The reheater is followed by an “economizer”, which preheats the condensed feedwater recycled back to the boiler tubes in the furnace. The final recovery section is the “air heater”, which preheats the ambient air used for coal combustion. The flue gas exhausted from the boiler passes through PM and other air emissions control equipment before being vented to the atmosphere through a stack.

c. Coal Utilization Processes 221. A coal-fired power plant or CHP normally uses five basic coal utilization processes: i) Stoker-fired; ii) Pulverized coal (PC); iii) Cyclone-fired; iv) Fluidized-bed combustion (FBC); and v) Coal gasification (IGCC). Pulverized coal is the coal-firing configuration predominately used at great number of existing power plants around the world, and is also most frequently selected for new coal-fired power plant projects. Fluidized-bed combustion and coal gasification are newer technologies that, depending on project specific requirements, can be considered as alternatives to building a new PC-fired power plant. Cyclone and stoker firing are older technologies that are generally not considered when building new coal-fired power plant.

d. Stoker-fired Coal Combustion 222. Stoker-fired coal combustion is the oldest boiler coal-firing design. In a stoker-fired boiler, the coal is crushed and burned on a grate. Heated air passes upward through openings in the grate. Stokers are classified according to the way coal is fed to the grate - as


Appendix 3-63

underfeed stokers, overfeed stokers, and spreader stokers. Stoker firing coal combustion is an obsolete technology for new coal-fired power plant because the other newer coal combustion technologies provide superior coal combustion efficiency, applicability and other advantages. The majority of new stoker-fired boiler capacity is expected to occur at municipal solid waste combustor facilities and facilities burning solid biomass.

e. Pulverized-coal Combustion 223. Pulverizing coal into a very fine powder allows the coal to be burned more easily and efficiently. For a PC-fired power plant, the coal must first be pulverized in mill to the consistency of talcum powder (i.e., at least 70% of the particles will pass through a 200-mesh sieve). The pulverized coal is generally entrained in primary combustion air before being blown through the burners into the combustion chamber where it is fired in suspension. PC-fired boilers are classified by the firing position of the burners either as wall-fired or tangential-fired.

224. A PC-fired boiler consists of multiple sections. The pulverized coal is ignited and burned in the section of the boiler call the “furnace chamber” (or sometimes the “firebox”). Ambient air blown into the furnace chamber provides the oxygen required for combustion. The walls of the furnace chamber are lined with vertical tubes containing the feedwater. Heat transfer from the hot combustion gases in the furnace boils the water in the tubes to produce the high-temperature, high-pressure steam. The steam is separated from boiler water in a steam drum and sent to the steam turbine. The remaining water in the drum re-enters the boiler for further conversion to steam. The hot combustion products are vented from the furnace in a gas steam called collectively flue gas. Figure 6.4 below illustrates an example of a simplified schematic of PC-fired power plant.

Figure 6.4: Simplified Schematic of PC-fired Power Plant

Source: USEPA.

f. Cycles Coal Combustion

225. Cyclone coal combustion technology was developed as an alternative to PC-firing


Appendix 3-64

because it required less pre-processing of the coal and allows for the burning of low rank coals with higher moisture and ash contents. Cyclone boilers use burner design and placement (i.e., several water-cooler horizontal burners) to produce high-temperature flames that circulates in a cyclonic pattern. The coal is crushed to a 4-mesh size, and then fed tangentially with primary air, to a horizontal cylindrical combustion chamber. In this chamber, small coal particles are burned in suspension, while the larger particles are forced against the outer wall. The high temperature developed in the relatively small boiler volume, combined with the low fusion temperature of the coal ash, causes the ash to form a molten slag, which is drained from the bottom of the boiler through a slag tap opening. Cyclone power plants have high nitrogen oxides (NOx) emission rates and therefore no new cyclone boilers are expected to be built.

g. Fluidized-bed Combustion 226. The term “fluidized” refers to the state of the bed materials (fuel and inert materials or sorbent) as gas passes through the bed. In a typical FBC power plants, combustion occurs when coal and a sorbent, such as limestone, are suspended through the action of primary combustion air distributed below the combustor floor. The gas cushion between the solids allows the particles to move freely, giving the bed a liquid-like characteristic (i.e., fluidized). FBC can occur in either atmospheric or pressurized boilers. Two fluidized bed designs can be used for atmospheric and pressurized FBC boilers: a bubbling fluidized bed or a circulating fluidized bed (CFB). An advantage of CFB boiler power plants compared to PC-fired power plants is fuel flexibility. A CFB boiler power plants can burn any rank of coal (including coal refuse), petroleum coke (a carbonaceous solid derived from oil refinery coker units or other cracking processes), and biomass without significant modifications.

227. The combustion temperature of a FBC boiler (1,500 to 1,650 F) is significantly lower than a PC-fired boiler (2,450 to 2,750 F), which results in lower NOx formation and the ability to capture sulfur dioxide (SO2) with limestone injection in the furnace. Even though the combustion temperature of a FBC boiler is low, the circulation of hot particles provides efficient heat transfer to the furnace walls and allows longer residence time for carbon combustion and limestone reaction. This results in good combustion efficiencies, comparable to PC-fired power plants.

228. Atmospheric CFB boilers have successfully been scaled-up and are operating at a number of facilities throughout the world. Calcium in the sorbent combines with SO2 gas to form calcium sulfite and sulfate solids, and solids exit the combustion chamber and flow into a hot cyclone. The cyclone separates the solids from the gases, and the solids are recycles for combustor temperature control. Heat in the flue gas exiting the hot cyclone is recovered in a series of heat recovery sections of the boiler to produce steam. The superheated steam leaving the boiler then enters the steam turbine, which powers a generator to produce electricity. Like PC-fired power plants, CFB boilers can be used either subcritical or supercritical steam cycles. Figure 6.5 illustrates an example of a simplified schematic of CFB boiler power plant.


Appendix 3-65

Figure 6.5: Simplified Schematic of CFB Boiler Power Plant

Source: USEPA.

229. Pressurized fluidized-bed combustion (PFBC) systems are FBC systems that operate at elevated pressure (typically pressures of 1~1.5Mpa) and produce a high-pressure gas stream at temperature that can drive a turbine. As with atmospheric FBC, two formats are possible, one with bubbling beds, the other with a circulating configuration. In a PFBC, the combustor and hot gas cyclones are all enclosed in a pressure vessel. Both coal and sorbent (for SO2 emissions reductions) have to be fed across the pressure boundary, and similar provision for ash removal is necessary. For hard coal (i.e., bituminous coal) applications, the coal and limestone can be crushed together, and then fed as a paste, with 25% water. As with atmospheric FBC, a combustion temperature between 1,500 to 1,650 F (800 to 900 C) has the advantage of less NOx formation than in PC combustion. In addition, the effectiveness of a carbon capture and storage (CCS) system is increased due to the high pressure within the PFBC cycle and higher partial pressure of the CO2 in the hot gas stream.

230. The initial or first generation PFBC designs are based on directly burning crushed coal in the chamber. The high-pressure gas is first expanded through a turbine and then heat is recovered from the turbine exhaust in a heat recovery steam generator to produce steam, which is used to drive a conventional steam turbine. More advanced second-generation PFBC system designs use a pressurized carbonizer to first process the feed coal into fuel gas and char (solid material that remains after light gases and tar have been driven-out during the initial stage of combustion). The PFBC burns the char to produce steam and to heat combustion air for the combustion turbine. The fuel gas form the carbonizer burns in a topping combustor linked to a combustion turbine, heating the gases to the rated firing temperature of the combustion turbine. Heat is recovered from the combustion turbine exhaust in a heat recovery steam generator (HRSG) to produce steam, which in used to drive a conventional steam turbine. These systems are also called advanced circulating pressurized fluidized-bed combustion combined systems. Figure 6.6 illustrates an example of a simplified schematic of PFBC power plant.


Appendix 3-66

Figure 6.6: Simplified Schematic of PFBC Power Plant

Source: USEPA.

h. Coal Gasification (IGCC)

231. An integrated gasification combined cycle (IGCC) power plant uses a coal gasification system to convert coal into a synthetic gas, which is then used as fuel in a combined cycle electrical generation process. Coal is gasified by a process in which coal or a coal/water slurry is reacted at high temperature and pressure with oxygen (or air) and steam in a vessel referred to as “gasifier” to produce a combustible gas composed of a mixture of carbon monoxide (CO) and hydrogen. This gas is often referred to as synthetic gas or syngas. Gasification processes have been developed using a variety of designs including moving bed, fluidized bed, entrained flow, and transport gasifiers. The hot syngas can be processed to remove sulfur compounds, mercury, and PM before it is used to fuel a combustion turbine generator to produce electricity. The heat in the exhaust gases from the combustion turbine is recovered to generate additional steam. This steam, along with the steam produced by the gasification process, then drives a steam turbine generator to produce additional electricity.

232. The efficiency of an IGCC power plant is comparable to the latest advanced PC-fired and CFB power plant designs using supercritical boilers. The advantages of using IGCC technology can include greater fuel flexibility (e.g., capability to use a wider variety of coal ranks), potential improved control of PM, SO2 emissions, and other air pollutants, with the need for fewer post-combustion control devices (e.g. almost all of the sulfur and ash in the coal can be removed once the fuel is gasified and prior to combustion), generation of less solid waste requiring disposal, and reduced water consumption when compared to a power plants using a supercritical boiler. Disadvantages of using IGCC include additional plant complexity, higher construction costs, and poorer performance at high altitude locations when compared to a power plant using supercritical boiler. However, IGCC power plants offer the potential for lower control costs of CO2 emissions because the CO2 in the syngas can be removed prior to combustion.

233. Over the past 5 years, a number of larger IGCC power plants projects have been


Appendix 3-67

proposed by a number of US electric utility companies. Some of these IGCC projects have been indefinitely delayed or canceled because of economic and regulatory factors, such as escalating project investment costs beyond initial estimates and unresolved cost recovery issues, etc.. Figure 6.7 illustrates an example of a simplified schematic of IGCC power plant.

Figure 6.7: Simplified Schematic of IGCC Power Plant

Source: USEPA.

i. Coal-water slurry fuel (CWSF) 234. To mitigate pollutant emission from coal-based combustion technologies, coal water slurry fuel (CWSF) or coal water mixture (CWM) fuel, a product of clean coal technology (CCT), was introduced as an alternative for traditional coal burning. CWSF is a mixture that contains 55-70 percent of coal particles, 30-45 percent of water, and less than 1 percent of additives. Customers have to equip a special boiler before a CWSF could be used. Once CWSF is fed into the special boiler and it undergoes the chemical reaction process in it, energy can be produced and released. This energy can be used in generating electricity, heating, support processing, and manufacturing. There are two outstanding characteristics of CWSF - cost advantage over fuel oil and environmental friendliness over coal.

235. During the last 30 years the U.S. Department of Energy (DOE) has been researching the use of Coal Water Fuels in boilers, Gas Turbines and Diesel Engines. When used in Low Speed Diesels the CWSF has resulted in thermal efficiency rating rivaling that of Combined Cycle Gas Turbines burning Natural Gas as their primary fuel. It has been suggested that slightly modified modular Diesel engine power plants burning CWSF are economically competitive with Natural Gas fired peaking electric plants in the 10 MWe to 100 MWe range of power supply. Figure 6.8 shows the simplified schematic boiler.


Appendix 3-68

Figure 6.8: Simplified Schematic of CWSF Boiler

Source: The Pennsylvania State University U.Ed # EMS 10-135, 2010.

236. The characteristics of each of the coal-firing configurations used in the power generation facilities are summarized in Table 6.4 below.

Table 6.4: Characteristics of Coal-firing Configurations in Power Plant

Coal-firing Configuration

Applications Worldwide (Power Generation in US)

Coal Combustion Process Description

Distinctive Design/Operating Characteristics

Stoker-fired Oldest coal-firing design first introduced to the power generation industry in the late 1800s

Not a significant contributor to overall MW generating capacity in US

New facilities are not expected to use this coal-firing design because of the superior performance and advantages of newer coal combustion technologies

Coal is crushed into large lumps and burned in a fuel bed on a moving, vibrating, or stationary grade. Coal is pushed, dropped, or thrown onto the grate by a mechanical device called a “stoker”

Spreader-stoker A flipping mechanism throws the coal into the furnace above grate. The fine coal particles burn in suspension while heavier coal lumps fall to the grate and burn in a fuel bed

Underfeed Coal fed by pushing the coal up underneath the burning fuel bed

Traveling grate Coal is fed by gravity onto a moving grate and leveled by a stationary bar at the furnace entrance

Pulverized-coal Combustion

Coal-firing design predominately used at existing power

Coal is ground to a fine powder that is pneumatically fed to a burner where it is mixed

Wall-fired An array of burners fire into the furnace horizontally, and


Appendix 3-69





plants in the US In 2008,

consumed ~92% of total coal consumed by US power plants

Currently coal-firing design of choice for new large coal-fired power plants (>400 MWe) built in US

with combustion air and then blown into the furnace. The pulverized-coal particles burn in suspension in the furnace. Unburned and partially burned coal particles are carried off with the flue gas

can be positioned on one wall or opposing walls depending on the furnace design

Tangential- fired (Corner-fired)

Multiple burners are positioned in opposite corners of the furnace producing a fireball that moves in a cyclonic motion and expands to fill the furnace

Cyclone Existing cyclone facilities s in US constructed prior to 1981

In 2008, consumed ~6% of total coal consumed by US power plants

New power plants are not expected to use this boiler type because of the commercial availability of FBC technology

Coal is crushed into small pieces and fed through a burner into the cyclone furnace. A portion of the combustion air enters the burner tangentially creating a whirling motion to the incoming coal

Designed to burn coals with low-ash fusion temperature that are difficult to burn in PC boilers. The majority of the ash is retained in the form of a molten slag.

Fluidized-bed Combustion

FBC power plants increasingly being built in US to burn low rank coals, coal refuse, and blends of coal with other solids fuels such as petroleum coke or biomass

In 2008, consumed approximately 2% of total coal consumed by US power plants

Atmospheric FBC facilities are currently operating in the US with generating capacities in the range of 250~300 MWe

No pressurized FBC boilers currently used for

Coal is crushed into fine particles. The coal particles are suspended in a fluidized bed by upward-blowing jets of air. The result is a turbulent mixing of combustion air with the coal particles. Typically, the coal is mixed with a sorbent such as limestone (for SO2 emission control). The unit can be designed for combustion within the bed to occur at atmospheric or elevate pressure. Operating temperatures for FBC are in the range of 800~900 C

Bubbling fluidized bed (BFB)

Operates at relatively low gas stream velocities and with coarse-bed size particles. Air in excess of that required to fluidize the bed passes through the bed in the form of bubbles

CFB Operates at higher gas stream velocities and with finer-bed size particles. No defined bed surface. Must use high-volume, hot cyclone separators to re-circulate entrained solid


Appendix 3-70





US power plants particles in flue gas to maintain the bed and achieve high combustion efficiency

Coal Gasification (e.g., IGCC)

Limited application to power plants to date

Some new proposed power plants projects using coal gasification as part of IGCC plant

Synthetic combustion gas (“syngas”) derived from an on-site coal gasification process is burned in a combustion turbine. The hot exhaust gases from the combustion turbine pas through a heat recovery steam generator to produce steam for driving a steam turbine/generator unit

Coal gasification units are unique from the other coal-firing configurations because a gaseous fuel (synfuel or syngas) is burned instead of solid coal and combines the Rankine and Brayton thermodynamic cycles as is the case for combined cycle power plant

Coal-water slurry fuel (CWSF)

Limited application to power plants to date

Few new proposed power plants projects using CWSF

CWSF combusted as usual liquid fuel (like Heavy Fuel Oil - HFO). Atomizer injects CWSF into the boiler chamber where CWSF is sprayed. Atomizer is developed especially for the CWSF to spray it with the right angle (2α) and with right droplet size.

Must avoid temperature below freezing, even though unlike fuel oils, the viscosity of CWF is relatively unaffected by temperature.

The smaller the particle size the more versatile the CWF is for application, however the finer the particle size the more difficult it is to manufacture.

Source: USEPA.


Appendix 3-71

j. Conclusion and Recommendation 237. The above studies suggest that a stoker-fired boiler might not be an ideal technical solution for use in the proposed CHP5, because its performance is poor compared to emerging newer coal combustion technologies.

238. Cyclone coal combustion technology is no longer competitive because of the commercial availability of FBC technology and therefore it is not an ideal option for the proposed CHP5 power plant.

239. Coal gasification combustion technology has limited application to date in electrical power generation and heating supply worldwide. Though there might be some cases where some new proposed power generation projects using coal gasification as part of IGCC plant, it is however not a favorable technical solution to the new CHP5 power plant.

240. CWSF combustion technology was just used in pilot projects, and not widely used in the power sectors. It is not a suitable combustion technology for the new CHP5 power plant.

241. Pulverized-coal combustion or PC boilers have been predominately used in the existing power plants of many countries around the world. In 2008, PC boilers consumed about 92% of total coal consumed by the power plants of US. Currently the PC combustion has been the design of choice for new large coal-fired power plants (>400 MWe) built in US.

242. However the PC boilers have some disadvantages compared to fluidized-bed boilers. International practices indicate that frequent maintenance is needed due to sever abrasion of a pulverizer. On top of that, efficient equipment to remove nitrogen oxide (NOx) and sulfur dioxide (SO2) emissions must be installed. The additional equipment would consequently increase the overall cost and reduce the operational efficiency of the entire system.

243. Fluidized-bed combustors (FBC) are boilers of a more recent design and were developed for solid fuel combustion. FBC are inherently suited for various fuels, including low-grade fuels such as petroleum coke, coal refuse, municipal waste, and biomass materials. Even though FBC boilers do not constitute a large percentage of the total industrial boiler population, they have gained popularity in the last few years, due primarily to their capabilities to burn a wide range of solid fuels and their low- nitrogen oxide (NOx)/sulfur dioxide (SO2) emission characteristics. The combustion temperature of a FBC boiler (800~900°C) is significantly lower than a PC-fired boiler (1300~1500°C), which results in lower NOx formation and the ability to capture sulfur dioxide (SO2) with limestone injection in the furnace.

244. There are a limited number of disadvantages for CFB boilers, for example, abrasion of combustion chamber and higher level of operational skills, etc. These could be resolved by well designed maintenance procedures and training. Overall the FBC design is technically matured, operationally reliable, commercially available, and economically viable, it is therefore recommended for application in the CHP5.

D. Technical Conditions of Main Equipment

1. Compatibility of Turbines, Boilers and Generators

245. The following principles should be applied to ensure the compatibility of the turbines, boilers and generators:

To take the continuous maximum rating (MCR) working condition as the nameplate working condition;

Feed steam under the steam engine regulating valve standard-sized sheet (VWO) to be at least 1.03 times the feed steam under steam engine maximum TMCR, to take it as a surplus reserved for unit ageing, design and manufacturing tolerance, as well as regulating adjustment;


Appendix 3-72

Boiler maximal continuous rate (BMCR) to be compatible with the steam flow under valve wide open (VWO) of steam engine; and

Generator’s rated capacity to be compatible with the turbine’s rated capacity when the generator’s power factors and hydrogen pressures are at their rated values and the cooling water temperatures of generator’s hydrogen cooler and the steam turbine under corresponding working condition are kept the same.

246. The detailed horizontal and vertical arrangement of the major equipment in the main workshop is shown in Drawing TA7502-MON-J02 and TA7502-MON-J03.

2. Boiler

247. As proposed, three 525 ton/hr super high-pressure boilers will be installed in Phase I, while three 525 ton/hr super high-pressure boilers and one 525 ton/hr high-pressure boiler will be installed in Phase II. The boiler design is a high-temperature, super-high-pressure, drum-type natural circulation, single furnace, one-time reheating balanced-draft circulating fluidized bed technology, indoor arrangement, dry bottom and full-steel frame, and complete suspended structure. Light diesel is to be used for boiler ignition and combustion aid. The lowest non-combustion add rate is 30% of BMCR. The boiler’s main technical parameters are tentatively proposed and shown in the following Table 6.5.

Table 6.5: Boiler’s Main Technical Parameters

Description of Parameter Unit BMCR

Steam flow at maximum continuous rating ton/hr 525

Superheater outlet pressure MPa(g) 13.7

Superheater outlet temperature oC 540

Feet water temperature oC 248.9

Primary air temperature at AH outlet oC 244

Sec air temperature at AH outlet oC 244

Gas air temperature at AH outlet oC 140

Consumption of coal ton/hr 71.9

Calculated boiler efficiency(calculated by LHV) % 91.45


248. The C&I systems provided with the boiler include:

Control system for regulating blowing ash in boiler: the system shall include all primary measurement instruments and control equipment (including a PLC control panel and electric panel) required to control process systems such as ash blower, steam source pressure-reducing station, and draining system.

Flue gas temperature sensor and control panel: the device is equipped with a local control panel. The flue gas temperature sensor shall be capable of being inserted, withdrawn and paused, or automatically withdrawn in case of overheating. The displacement transformer with two-wire ports will transmit 4～20 mA signal to decentralized control system (DCS).

A leakage control device for the air pre-heater: DCS communication interface and hardwire interface signals are inserted in this device to monitor and operate interval automatic control device through the operator station of DCS.


Appendix 3-73

Boiler pressure control valve (PCV) control device: integrated PCV control device (including controller, local electric box, primary measurement element and the metering instrument valve) is provided with the boiler.

An industrial television system for displaying the boiler chamber flame: the boiler shall be equipped with two sets of industrial television system, each of which includes a lens pipe, a video camera as well as the cooling devices of the video camera and lens with installation accessories.

Furnace Safety Supervision System (FSSS) related stokehole equipment: the boiler shall have field apparatus (devices) related to FSSS, including an oil gun and its retractor device, a high-energy igniter, a fuel and ignition oil pipe flow meter, a pressure regulator valve, a flow control valve, an inlet valve, a blow down valve, a solenoid valve, a field logic switch for each oil gun, and an onsite ignition tank, all of which shall have signal interface with FSSS.

Other requirements of C&I: All local displaying instruments shall be provided within range of boiler; sockets are required to be reserved at temperature measurement points on the boilers and the pressure measurement point shall be provided with primary door and accessories. The local measuring instruments (manometer, logic switch, and liquidometer) provided with the main part shall be supplied with installation accessories (primary door, secondary door, and blow down valve). The steam turbine and its regulating valve and electrically-driven gate shall have proven operating records to ensure their controllability and reliability so as to meet requirement of thermal engineering control. The electrically-driven gate will employ an intellectual integral pattern, and will be equipped with on-off travel-limit switches along the close and open direction of valve, which are four open and four close patterns. Contact rating is 220VAC, 3A. The solenoid valves provided with the boiler shall be imported products.

3. Steam Turbine

249. The nameplate working condition (TMCR working condition) of the steam turbine refers to the working condition under the parameters of rated primary steam, when the main steam flow rate is the rated feeding steam flow rate, and the back-pressure (corresponding to the annual mean temperature) and supplemental water flow rate reach the nominal conditions, the generator can generate nameplate power, deducting non-coaxial excitation and other power consumption, safely and continuously with rated power factor and rated hydrogen pressure at any time during the lifetime.

250. In the condensing mode, the steam-extracting turbines of Phase I will be 450 MW of power generation capacity (total 820 MW). Under rated steam extracting condition, each steam-extracting turbines will have 135 MW of power generation capacity and a steam-extracting capacity of 280 ton/hr. Based on the detailed calculations, under rated steam-extracting condition, the rated heating capacity of the three turbines in Phase I will be 587MW (total 1281 MW), and the rated power generation of the three turbines for Phase I will be 405 MW (total 745 MW).

251. The extracting and condensing steam turbine will have the configuration of high-pressure, double cylinders, seven stage heaters, water-cooling extracting and condensing steam turbine. The detailed working parameters (TMCR) are shown in Table 6.6. The back-pressure turbine will have the configuration of high-pressure, single cylinder, and three stage heaters. The detailed parameters of the back-pressure turbine are shown in Table 6.7.


Appendix 3-74

Table 6.6: Working Parameters of Extracting and Condensing Steam Turbine

Description of Parameter Parameter Value

Rated power (TMCR) 150 MW

Rated inlet steam flow(TMCR) 500ton/hr

Steam pressure at the main stop valve(TMCR) 13.24 MPa (a)

Steam temperature at the main stop valve 535 ºC

Extraction steam pressure of high-pressure 0.98 MPa(a)

Extraction steam volume of high-pressure 100 ton/hr

Extraction steam pressure of low-pressure 0.19 MPa(a)

Extraction steam volume of low pressure 180 ton/hr

Feed water temperature 235 ºC

Designed back-pressure 4.9 kPa (a)

Regenerative system 7 stages (two high-pressure heaters, four low pressure heaters, one deaerator)

Driving means of feed pump Electric-driven, hydraulic coupling speed control

Source：TA Team estimates.

Table 6.7: Working Parameters of Back-pressure Steam Turbine

Description of Parameter Parameter Value

Rated power (TMCR) 70 MW

Rated inlet steam flow(TMCR) 410ton/hr

Steam pressure at the main stop valve(TMCR) 8.8 MPa (a)

Steam temperature at the main stop valve 535 ºC

Exhausting steam pressure of cylinder 0.4 MPa(a)

Exhausting steam temperature of cylinder 162 ºC

Feed water temperature 216 ºC

Designed back-pressure 0.4 MPa(a)

Regenerative system 3 stages (two high temperature heaters, one deaerator)

Driving means of feed pump Electric-driven, hydraulic coupling speed control


4. Generator

252. In accordance with the turbine capacity and local electric system requirement, a suitable generator has been selected. The detailed parameters of the generator are shown in the Table 6.8.


Appendix 3-75

Table 6.8: Working Parameters of Generator

Items Description

Type Three-phase AC synchronous alternator

Rated power 150 MW (rated power-factor, rated hydrogen pressure)

Rated power factor 0.85 lagging

Rated voltage 15.75 kV

Type of cooling Stator winding water-cooling, rotor winding and stator-core hydrogen-cooling


5. Energy Balance

253. At rated steam-extraction volume, the steam-extraction turbine will have 135MW power generation capacity and 100 ton/hr of high-pressure steam and 180 ton/hr of low pressure steam extracting capacity. The back-pressure turbine will have an exhausting steam capacity of 345 ton/hr. Based on the detailed calculations, under maximum heating capacity conditions, the maximum heating capacity of six turbines will be 1281MW, and the power generation of six turbines will be 745 MW. The project will be implemented in two phases. During phase I, three x 150 MW steam extracting turbines, with total 587 MW heating capacity, are planned. During Phase II, an additional two x 150 MW steam extracting turbines, one x 70 MW back-pressure turbine, and two peak boilers will be installed, with a total of 694 MW heating capacity. The heating and power generation capacity under ratated extraction steam conditions are shown in Table 6.9.

Table 6.9: Heating and Power Generation Capacity under Rated Extraction Steam

Description Extraction-condensing Turbine

Back-pressure Turbine

A B

1 Quantity (set) 5 1

2 Rated Extraction Steam (ton/hr) 280 345

3 Power Generation Capacity (MW) 135 70

4 Rated Heating Capacity (MW) 1281

5 Total Power Generation Capacity under Rated Extraction Steam (MW) 745


a. Heating Capacity Balance 254. The new CHP plant is planned to be constructed in two phases, including Phase I that will be completed by 2015, and Phase II which will be completed by 2020. As described above, the heating demand by 2015 will be 527 MWt (453 Gcal/hr), and 1281 MWt (1,101Gcal/hr) by 2020. During Phase I, three boilers, each with 525 ton/hr of capacity, are expected to be installed with a total design power generation capacity of 450 MW and a total design heating capacity of 587 MWt (or 504 Gcal/hr), which will meet the heating and power demand.


Appendix 3-76

According to international design specifications, detailed data tentatively estimated for the proposed CHP5, as well as the turbine manufacturer’s technical specifications, heating capacity balances are listed in Table 6.10 below.

Table 6.10: Heating Capacity Balance by Phase I


1 Quantity (set) 3

2 Extraction Steam (ton/hr) 280

3 Heating Capacity (MW(Gcal/hr)) 527(453)

4 Heating Capacity by Temperature and Pressure Reducer (MW) 60(51)

5 Total Heating Capacity (MW(Gcal/hr)) 587(504)

6 Total Heating Demand (MW(Gcal/hr)) 527(453)

7 Balance(MW(Gcal/hr)) 60(51)

Source: TA Team

255. Upon completion of Phase II, a total five super high-pressure steam boilers, each with a capacity of 525 ton/hr and one high-pressure boiler with a capacity of 525 ton/hr, and five extraction-condensing turbines and one back-pressure turbine are expected to be installed with a total design power generation capacity of 820 MW and a total design heating capacity of 1,281 MWt (or 1,101 Gcal/hr). The heating balance for Phase II is shown in Table 6.11.

Table 6.11: Heating Capacity Balance by Phase II


Back-pressure Turbine

1 Quantity (set) 5 1

2 Max. Extraction Steam (ton/hr) 280 345

3 Power Generation Capacity (MW) 84 70

4 Max. Heating Capacity (MW(Gcal/hr)) 879(756) 211(182)

5 Heating Capacity by Temperature and Pressure Reducer (MW(Gcal/hr)) 191 (164)

6 Total Heating Capacity of Power generation Units (MW(Gcal/hr)) 1,281 (1101)

7 Total Heating Load (MW(Gcal/hr)) 1,281(1101)

8 Balance 0(0)


b. Power Balance of Supply and Demand 256. Based on the forecast of electricity demand, the power generation capacity of the existing power plants and the proposed CHP5, the power balance of supply and demand in the CES has been calculated and shown in Figure 6. 9. It indicates that 158 MW of power supply by 2015 and 173 MW of power supply by 2020 are to be covered by other power sources, though CHP5 is proposed to provide 450 MW of power supply by 2015 and 820 MW by 2020. That is, other power plants should be planed to cover the balance power supply of the CES as soon as possible. The power balance of supply and demand in the CES BY 2030 is shown in Figure 6.9.


Appendix 3-77

Figure 6. 9: The Power Balance of Supply and Demand in the CES by 2030

E. Thermodynamic System

257. The thermal system design will ensure a safe and economical operating unit and satisfy the requirements of the contract. The steam/water system will be unit type in this project. The thermodynamic cycle of the extracting steam turbine employs a seven-stage regenerative extracting steam system, equipped with two high-pressure heaters, one deaerator and four low-pressure heaters. The thermodynamic cycle of the back-pressure steam turbine employs a three-stage regenerative extracting steam system, equipped with two high-pressure heaters and one deaerator. The schematic of these thermodynamic systems is shown in Drawing 3.

1. Extracting Steam System

258. The steam turbine has a seven-stage non-adjustable steam extractor to work as a heat source for two high-pressure heaters, one deaerator, and four low-pressure heaters.

259. Except for the seventh stage extraction pipe, the first, second, third, fifth, and sixth stage extraction pipes are all equipped with an electric-driven stop valve and a pneumatic check valve, to protect the steam turbine from water inflow and over-speed.

260. The extracting steam for district heating is adjustable, which is extracted from a middle pressure cylinder. The extraction line is equipped with a pneumatic check valve, an electric-driven regulating valve and an electric-driven stop valve.

2. Water Supply System

261. The water supply system will be equipped with a spray type deaerator, which can meet the requirements of sliding pressure operation. The output of the deaerator is 525 ton/hr。. The capacity of water tank is 100 m3, which can meet the water supply consumption at the maximum evaporative capacity of the boiler in ten minutes.

695 695 715 705 705 705 705 705 765 815 815 815

0 0 0 0

450 450 450 450 450

820 820 820

67 124 147 229

158 239 328 389 410

93 395

686

0

500

1,000

1,500

2,000

2,500

2011 2012 2013 2014 2015* 2016 2017 2018 2019 2020 2025 2030

Total generation of exisitng power plant of CES (MW)


Appendix 3-78

262. The water supply system is to adopt a independent system. Three motor-driven variable speed feed water pumps are designed for each unit under the Project, whose capacity is 50% of the largest amount of water supplied. Three 100% capacity high-pressure heaters are to be equipped.

3. Condensate System

263. The system is designed in accordance with the possible condensing capacity of the steam turbine under VWO conditions, plus the recurrent drainage quantity, normal feed water and steam and water loss for district heating.

264. The condensate pumping system employs primary pumps. Every boiler is equipped with three variable frequency condensate pumps with a capacity of 50% of the maximum condensate flow, to meet the unit's operation under condensing and heating condition.

265. The condensate system is equipped with a four-stage surface type low-pressure heater with full capacity. The condensate water after the cooler for vapor lock enters the first low-pressure heater installed on the exhausting apparatus, and then passes through the second, third, and fourth low-pressure heaters then flows into the deaerator.

4. Drainage and Steam Releasing Device

266. The condensate water in the heaters flows by gravity. Under normal operation, condensate water in the high-pressure heater cascades finally into the deaerator, while condensate water in the low-pressure heaters cascades into the expansion tank of drained water from the steam turbine. In case of accidents and low load, the condensed water in the high-pressure heaters is discharged to a dedicated expansion tank as a precaution, while that of low-pressure heaters is transferred to the steam releasing device.

5. Vacuum-Pumping System

267. The vacuum-pumping system of the steam condenser has three water ring vacuum pumps capable of delivering 100% of the needed capacity. Under normal operation, one pump works and the other two are for back-up. The three pumps can all be operated when the unit starts to operate.

6. Auxiliary Steam System

268. The start-up steam for the first unit will be supplied by the existing high-pressure system. It is not necessary to install start-up boilers.

7. Steam System for District Heating

269. The primary heat exchanging station of the district heating system under the Project will provide hot water with supply water temperature of 135ºC and return water temperature of 70ºC to secondary heat exchanging stations distributed in the urban areas. Main and peak load heat exchangers will be designed for the heat exchanging station. The district heating diagram is shown in Drawing TA7502-MON-J04. The heat exchanging principle of the primary heating exchanging station is shown in Figure 6.10.


Appendix 3-79

Figure 6.10: Heat Exchanging System Diagram for District Heating

Source: TA Team

270. During heating season, through the main heat exchanger, hot water for district heating will be preliminarily heated up from 75℃ to 110℃ by the steam as the heat source of district heating extracted from the low pressure cylinder of the extracting steam turbine. The nominal flow rate of the extraction steam from the low pressure cylinder will be 180 ton/hr and its pressure and temperature will be 0.196MPa and 176.3℃.

271. In case of extreme cold climate which requires higher hot water temperature for district heating than 110℃, the peak load heat exchanger will be put into service to heat up hot water from 110℃ to 135℃. The extraction steam from middle pressure cylinder of the turbine will be used as heat source for peak load heat exchanger. The heating extraction lines of the three units will be combined and linked to the common heater. The nominal flow rate of the extraction steam from the low pressure cylinder will be 100 ton/hr and its pressure and temperature will be 0.9807MPa and 345.9℃.

272. The condensate water from the heat exchangers flows into the drainage tank, and then is pumped into the deaerator by a condensate pump. The condensate water returns the deaerator at 104 ºC and the residual enthalpy will be recovered.

273. The normal make-up water for the district heating system will be the deoxidized and softened water. The make-up water pump will be connected to the return common pipeline of the district heating system, and constant system pressure is achieved through matching the speed of the make-up water pump to the district heating system pressure.

274. The condensate water from the heat exchangers flows into the drainage tank, and then is pumped into the deaerator by a condensate pump, which condensate water returns the deaerator at 104 ºC to recover the residual enthalpy.

275. The normal make-up water for the district heating system will be the deionized and softened water. The make-up water pump will be connected to the return common pipeline of the district heating system, and constant system pressure is achieved through matching the speed of the make-up water pump to the district heating system pressure.


Appendix 3-80

F. Combustion System

276. The CFB boiler is recommended for CHP5 project. The furnace design features a vertical chamber and fine water-wall tubes in which the CFB process takes place. This includes fluidization of the bed material: fuel, limestone, ash or sand. Properly-sized fuel is fed into furnace and burned at a relatively low temperature to avoid the product of NOx. For the flue gas desulfurization, fine grain limestone is introduced into the furnace where it is calcined and oxidized. This enables a reaction with the sulfur dioxide formed during the combustion of sulfur containing fuel. The product of this reaction is calcium sulfate, a solid easy to remove from the furnace along with bottom ash. This combustion technology reduces the NOx and SO2 from stack emission.

1. Properties of Coal

277. The coal required by the CHP5 Project will be supplied by two coal mines, namely the Baganuur and the Shivee-Ovoo, in which Baganuur will provide 30% of the coal while Shivee-Ovoo will provide 70%. The composition analysis of the coal and ash from the two mines are shown in Table 6.12 and Table 6.13.

Table 6.12: Characteristic of Coal

Coal Mine Baganuur Shivee-Ovoo

Mean Range Mean Range

Proximate Analysis Unit

Volatile matter % 42 39~45 45 36~48

Fixed carbon % 32 30~40 31 28~36

Moisture (Inherent) % 11 8~13 8 3~12

100% 100%

Total moisture as-received basis % 33 30~40 39 37~44

Calorific value as-received basis (dry) Kcal/kg 3,400 2,600~3,500 2,900 2,700~3,400

Grindability-Hardgrove - 50 40~60 64 62~66

Ultimate Analysis

Carbon % 73.2 72.89

Sulfur % 0.6 0.4~0.8 0.61 0.6~0.9

Hydrogen % 4.7 4.19

Oxygen % 20.6 21.38

Nitrogen % 0.9 0.93

100% 100%



Appendix 3-81

Table 6.13: Ash Composition of Coal

Compound Unit Baganuur Coal Shivee-Ovoo Coal

SiO2 % 54.8 44.44

Al2O3 % 12.5 14.51

Fe2O3 % 10 8.03

CaO % 12 15.24

TiO2 % 0.6 0.64

MgO % 1.8 3.96

MnO % - -

SO3 % 6.4 10.87

P2O5 % - -

Na2O % 0.6 0.81

K2O % 1.3 1.5

100% 100%


2. Firing system

278. The particle size of coal should be less than 10 mm after being crushed. The coal is crushed in a single stage, then fed into a coal bunker. The firing system of each boiler will be equipped with the following:

six 33.33% level drag link conveyors equipped with frequency converter;

two 50% primary constant speed air fans of, electric motor-driven, centrifugal type;

two 50% forced draft constant speed fans, electric motor-driven, centrifugal type;

three 50% HP constant speed fluidizing fans, electric motor-driven, roots type;

two 100% limestone rotary feeders, equipped with frequency converter;

two 100% roots limestone fans. Each boiler will have two 50% constant speed induced double inlet draft fans, electric motor-driven, centrifugal type;

four steam air heaters for each primary air and secondary air inlet; and

one ESP with two chambers and four fields.

3. Firing System and Auxiliary Equipment

279. The coal feeding system is designed to distribute coal from a bunker via six conveyers to the boilers. Each boiler has two coal bunkers with an 8-hour coal consumption capacity for a steam generator at BMCR condition. Each coal bunker has three hopper outlets. During normal operation, each conveyer is in operation with maximum 33.33% of design capacity. In case of failure, three conveyers can be omitted and the system still functions at 100% of design capacity. The coal is distributed from the bunker by a one level drag link conveyor equipped with frequency converter. The conveyer to the feeding points is located at the boiler front wall. 280. The limestone system is designed to transport limestone from the limestone handing house to the boiler house by two pneumatic tanks, then distribute limestone from the limestone silo via two conveyers to each boiler. The limestone will be fed into one limestone


Appendix 3-82

silo from the limestone handing system, then transported to a boiler house by two air-powered tanks with one operating and one on standby. Each boiler has one limestone silo with an 8-hour limestone consumption capacity for the steam generator at BMCR condition. Two silo outlets are installed at the bottom of the limestone silo. Each silo outlet leads to one conveyer. During normal operation both conveyers are in operation with 50% of the required limestone quantity. In case of failure one conveyer can be operated at 100% of the design capacity. A frequency converter is used with the rotary feeder. The dosing of the limestone powder can be controlled using a variable speed rotary feeder. Two limestone Roots fans are installed after the rotary feeders

281. The combustion air system will supply the CFB furnace during start-up and normal operation with the air required for sealing, cooling, fluidizing, transportation, and combustion. Total air injected to the CFB furnace consists of primary air, secondary air, limestone transportation air, and high-pressure fluidizing air for the loop seal. The forced draught fan (FD-fan) compresses the ambient air to a certain degree on the air resistance of the system. Downstream of the FD fan air flow is distributed into the secondary air and sealing air systems. A steam coil air pre-heater is installed before the inlet of fan to increase air temperature to prevent the decrease of the flue gas temperature below the dew-point of acid and water. The temperature of the secondary air is increased by the tubular air pre-heater. Downstream of the tubular air pre-heater the secondary air flow is further distributed into secondary air flow lower level. Each secondary air mass flow is measured and regulated by control dampers. The control damper of the FD-fan controls the air pressure downstream of the tubular air pre-heater according to the boiler load. The total air is controlled by the secondary air damper position. The O2 controller corrects the load depending set point for total air. The force draught fan consists of a single flow, constant speed, centrifugal compressor with a control damper. There will be 2 forced fans and each has the designed capacity of 50% of the total required volume flow.

282. The pressure of the primary air is increased to the pressure requirements of the CFB furnace (fluidizing of the bed material) by the primary air fan. If necessary, the steam coil air pre-heater will increase the temperature of the primary air to prevent the decrease of the flue gas temperature below the dew-point of acid and water. Downstream of the steam coil air pre-heater, the primary air is re-heated by the tubular air pre-heater. The primary air will distributed into four air duct burners then to primary air nozzle grid and supply the coal feeding air. Each primary air mass flow is measured. The primary air fan consists of a single flow, constant speed, and centrifugal compressor with a control damper. There will be 2 primary fans and each has the capacity of 50% of the total required volume flow.

283. The steam coil air pre-heater (SCAH) prevents the metal surface of the flue gas side air pre-heater from corrosion due to a drop of the flue gas temperature to below the acid dew-point. The steam coil air pre-heater is designed in the way that it protects the air pre-heater at different air intake temperatures as well as at different sulfur contents of the fuel from corrosion.

284. The air flow through the tubular air pre-heater is arranged inside of the tubes. The primary and secondary air are carried in separate tubes. The flue gas temperature is decreased at BMCR and design coal from 320 °C to 140 °C by an increase of the primary air and secondary air temperature. The air leakage (from primary air and secondary air to flue gas) ratio will be not more than 3%.

285. The fluidizing air fans compress the air up to a certain pressure depending on the fluidizing requirements of the loop seal system. Downstream of the fluidizing air fan the air flow goes to “U” valve. The air mass flow is adjusted by electrical dampers and the sum of mass flows is measured. In the case where a lubricating air for the cyclone and downcomer is not needed the surplus air mass flow is added to the primary air mass flow by adjusting a electrical damper. The fluidizing air fan provides a constant air mass flow to the system.


Appendix 3-83

286. Flue gas system. The purpose of the flue gas system is to transfer heat to the water/steam cycle in the downstream heating surface section and to the primary and secondary air in the tubular air pre-heater. The flue gas temperature is decreased at BMCR and design coal from 895°C to 140°C. The ESP decreases the dust content of the flue gas to the required dust content. The system consists of the following: a downstream heating surface section, a tubular air preheater, an ESP, and an induced draught fan. The ID-fan is a double-inlet flow centrifugal type. It controls the pressure downstream of cyclone to a pressure of ~20 Pa.

287. Stack. There is one single tube taper stack for the three boilers for Phase I, and another stack for Phase II. The outlet diameter of the stacks is Φ5.5m with a design height of 250 m.

288. Diesel system. A diesel system will be used for start-up and stabilization of the combustion (under 30% BMCR operating conditions) of the plant CFB boilers. A complete oil storage and feeding facilities will be provided. This diesel system will provide fuels for one boiler start-up and its associated oil consumption and one boiler stabilization and its associated combustion oil consumption; the total oil consumption is expected to be about 16.8 ton/hr. For this project, the diesel system will supply oil to a diesel generator. Complete oil storage and feeding facilities will be provided. The fuel diesel system capacity will provide fuels for all diesel units operating at MCR condition for 24 hours.

289. The oil will be transported by piping to the site from the Process Plant. There will be an oil tank with an effective volume of about 120m3 in the oil area. At the bottom of the tank there will be a steam coil heater, the oil will be transported to boiler area by the oil transporting pump, there are two 100% capacity oil transporting pump (one operation and one standby). There will be an oil filter at the inlet of the oil transporting pump. The oil transport pumps are located in oil pump room. In that oil room, there is a waste oil pit, and the waste oil will be delivered to waste oil treatment room by two waste oil pumps (one standby and one operation).

290. The boiler ignition will uses mechanical atomization and will have a steam purging system. The oil supply pressure at the interface of boiler oil system will be 2.8 MPa(g), with an oil flow capacity of 8.2 kg/h. A control valve will be employed for oil feeding control, in order to ensure the correct pressure. The requirements for output and atomized particle size of the oil gun will be met.

291. A diesel generating system will be installed with boiler system. Diesel generators will be located in this house. Waste oil pump and a waste oil pit also are located in this house. The oil pump house will be distributed into: pump room, control room, switchboard room, waster oil retreated room and aerator room. The oil pump house is 29 m x 9 m and 4m high.

G. Coal Conveying System

1. Coal Source, Coal Properties and Transport Method

292. The CHP5 power plant will use coal from the mines of Baganuur and Shivee-Ovoo. The proximate analysis and the ultimate analysis, as well as physical property of the coals are shown in Table 6.12 above. Compositions of the ash after combustion are also shown in Table 6.13. In order to transport the coal from the mines to the plant, an ordinary open top wagon will be used and the coal will be shipped using the existing railway system. Each engine head has a capacity of 3,200 tons, while the net load capacity of the train is about 2,200-2,400 tons. Daily maximum coal consumption is 14,440 tons in the winter, and the daily maximum unloading capacity required is about 7 trains.

2. Coal Unloading Device

293. The coal is unloaded using a “C” type turning forward-backward machine. The


Appendix 3-84

machine is equipped with heavy-duty gearing, a transfer working station and deadhead switching machine to keep the operation of the entire unloading process under control. The coal receivers under the turning machine are equipped with vibrating coal feeders. Two sets of turning machines will be installed for the CHP5 by phases. One unit will be installed in Phase I, and the other will be installed in Phase II.

294. There will be three railway lines specially designed for coal unloading inside of the CHP5 plant. One is for parking loaded wagons, one is for parking unloaded wagons and one is for wagons in motion. There will be a paved field alongside of the loaded wagon line. If the turning machine fails to work, coal can be unloaded by manpower. Furthermore, the pavement ground can be the site for cleaning turning machines.

295. In addition, due to the extreme cold winter in UB, it is necessary to construct a warm house to defrost the coal. Hot air units, consisting of fans, steam/air heat exchangers, and filters, will be installed to heat the warm house using extraction steam or exhaust steam from the back-pressure turbine.

3. Coal Storage

296. The designed coal storage amount can provide more than 30 days usage for the 820 MW units. The coal storage yard is equipped with special walls to prevent coal loss due to wind, sun or rain. In addition, the coal yard will be equipped with the coal loading, unloading, moving and leveling machines.

297. The coal yard will be constructed in phases. The coal yard proposed for Phase I will be constructed on the area close to the existing coal yard with dimensions of 250 m long by 160 m wide and 300,000 tons of coal storage capacity. New systems and facilities will be installed including one new bucket wheel stacker and reclaimer and the auxiliary facilities for a coal conveying system. In Phase II, the coal yard is to be extended further east, and the storage capacity of the coal yard needs to be increased to 600,000 tons matching the demand of both Phase I and Phase II. During Phase II, the existing CHP3 coal yard is to be upgraded and one additional bucket wheel stacker and reclaimer and related auxiliary equipment will be installed. Coal for Phase II will be transported by another conveying system on the west side. After Phase II, the coal yard will be 500 m long by 160 m wide, with a total storage capacity of 600,000 tons.

4. Equipment for Removing Impurities and Coal Crushing

298. The power plant plans to use raw coal that is mixed with coarse coal, metals, stones and wood etc., which could bring negative impacts on the safe operation of the power plant. Devices to remove these impurities shall be considered in designing the coal transport system. First, a coal comb shall be installed at the coal scuttle outlet of the turning machine to separate potential impurities more than 300 mm in size from entering the system. Next, cleaning facilities shall be installed in the following systems to separate unwanted material, stones and wood from the coal.

299. The coal crusher room, situated behind the coal yard, will use a rake-type roller screen system. Only particles less than 10 mm in diameter will pass through. The coal crushing equipment is a heavy-duty ring type.

5. Coal Conveying System and Operation Mode

300. The coal conveying system will utilize a belt conveyor to move coal from the turning unloading room to the coal yard. The coal conveying system from the coal yard to the raw coal scuttle of the main power house will have two belt conveyors to meet the requirements of providing coal to the raw coal scuttle. The coal unloading for the coal bunker bay will use a two-sided electric plow discharger. The coal conveying system diagram is shown in Drawing TA7502-MON-M01.


Appendix 3-85

301. Except for the one-way belt conveyor used from the turning room to the coal yard, the entire coal transport system uses a double-way belt conveyor, considering one way for operation and the other for back-up, with the condition that two ways can operate at the same time. The belt conveyors, exchange stations and the coal crusher room are all enclosed construction.

6. Auxiliary facilities and structures

302. A magnetic, tramp iron separator with a suspending draper-type for automatic iron discharging will be employed to remove ferrous metal waste from the coal . This will be a two stage system: one for in front of the coal crusher and one for behind the coal crusher.

303. Coal sampling device: (1) a coal sampling device used to monitor certain coal properties prior to entering the boiler will be mounted at the belt conveyor that enters into the main power house; another will be installed at the crushing and coal recycling facilities; (2) the sampling device used for monitoring the coal property entering the plant is mounted at the dumping track, and samples coal directly from train wagons.

304. Coal weighting device: (1) the coal entering the plant is measured by a static electronic track weighing apparatus which is installed on the dumping track before the turning machine in the plant; (2) the coal entering the boiler is measured by an electronic belt conveyor scale which is installed on the belt conveyor behind the coal crusher. 305. Other facilities: (1) a coal bulldozer storage house; (2) a coal conveyor, multiple–use building, including an electronic equipment room for the coal conveying system, a power distribution room and offices.

306. Control of the coal convey system: The coal conveyor system will employ a centralized monitoring and control system with a variety of mechanical equipment. The onsite control devices are available to facilitate the maintenance of equipment. The monitor screen is located in the centralized control room to monitor the sequential start and stop of each conveyor belt to select the operation modes as well as to deliver operating instructions, to show break-downs, and to record and manage operation reports.

H. Ash Handling

1. Ash Quantity

307. The coal consumption of each boiler per hour is shown in the following table.

Table 6.14: Coal Consumption of Each Boiler

Item Bagannur Shivee-Ovoo

Lower Heating Value (kcal/kg) 3,400 2,900

Ash content (%) 9.5 8.9

Coal consumption (ton/hr) 103 120


308. Based on the coal consumption and ash content in coal, the amount of ash generated is estimated and shown in the following table.


Appendix 3-86

Table 6.15: Ash Quantity of Each Boiler

Ash Type Unit Bagannur Coal Shivee-Ovoo Coal

Bottom ash ton/hr 4.65 5.07

Fly ash capture by ESP ton/hr 4.61 5.02

Particulate matter stack emission ton/hr 0.04 0.05

Total bottom & fly ash ton/hr 9.26 10.09

Note: The dust emission concentration of ESP is 50 mg/Nm3. It is assumed that 50% of the ash is fly ash the other 50% is bottom ash. The limestone is not included in above table.


2. Process Description

a. Fly Ash Conveying System

309. Fly ash air transport technology is developing quickly, and a pneumatic ash removal system has been widely applied in thermal power plants. In the ash handling system, a positive pressure, dense phase pneumatic ash-handling systems has been put into operation. The positive pressure dense phase pneumatic ash-handling system is one of the most internationally advanced air transport technologies available. The system use the air transport principle with dual-phrase distribution of gas and solid, and utilizes dynamical pressure conveying materials from compressed air. The pneumatic fly ash removing system diagram is seen in the Drawing TA7502-MON-H01.

310. Compared to the conventional dilute phase cone pump conveyor technology, its main features include: low conveyance air pressure, low conveying speed, long delivery distance, high ratio of conveyance ash to gas, and low energy consumption. Because of the small air consumption and the high concentration, the required diameter of ash conveying pipe is small and the investment cost of pipeline is low. Because the diameter of conduit pipe is small, the conduit pipe does not require wear resistant materials (only elbows or other flow restrictions need wear resistant material), and little maintenance is required. The positive pressure dense phase pneumatic ash-handling system is a safe, reliable, highly-efficient, and energy-saving system.

311. The current period of the project plan is designed on the basis of positive pressure dense phase pneumatic ash-handling system.


Appendix 3-87

Figure 6.11: Technological Process of the Ash Handling System

Source: TA Team

312. The fly ash conveying system design takes each furnace as a unit, and utilized the positive pressure dense phase pneumatic ash-handling system. The system capacity is designed to handle 150% of ash discharge amount while burning design coal. The capacity of the ash handling system for each furnace being 20 ton/hr.

313. The ash bucket of the dust arrestor has a gasifier. Its air source is the gasification fan of the ash bucket. Each furnace has two gasification fans, one for operation and one for back-up. An electric heater is installed in the exit air duct of the gasification fan. The parameters are: flow Q=22 m3/min, pressure P=0.058 MPa.

314. The pressure pneumatic ash handling system is equipped with a corresponding air compressor and purifier.

315. The two furnaces share one air compressor room, in which three sets of 30 Nm3/min air compressors and purifiers are installed, two for operation and one for back-up. The gas for the ash removal device is provided by the air compressor room.

316. The ash handling system has three ash bunkers, including two coarse ash pools and one fine ash pool. Each ash bunker has an effective volume of 1,200 m3. The three ash bunkers can store the amount of dust produced by two furnaces in over 48 hours. The ash bunkers are concrete structures with flat bottom and a diameter of 12 m.

317. Dust in the ash bunkers is discharged in two ways: transported via bulk cement trucks to users of comprehensive utilization; or, wetted by a wet stirrer and then transported via dump trucks to the ash pond for storage.

318. A gasification tank is designed at the basement of the ash bunker. The air source is provided by the gasification fan of the ash bucket. Four gasification fans are in the design: three for operation and one for back-up. An electric heater is installed in the exit air-duct of the gasification fan. Air enters the ash bunker after being preheated to fluidize the dust inside so that the dust can be discharged smoothly. The parameters are: flow Q=12.61 m3/min, pressure P=0.078 MPa. In addition, an electric air heater is installed at the exit of each gasification fan, with a power of 40 kW and a heating temperature of 176℃.

b. Bottom Ash Conveying System

319. The bottom ash handling system will be used to collect and transport bottom ash from the furnace or boiler. Bottom ash coolers continuously remove the bottom ash from the furnace. After cooling it is discharged to the bottom ash bin by two chain bucket conveyors in

Ash bucket of the precipitator, ash bucket of

the economizer

Positive pressure

pneumatic system

Dry dust user

Automobile bulk loader

Ash bunker

Bulk cement

truck

Dump truck

Wet mixer Ash pond or ash user


Appendix 3-88

series. It will further be transported to the ash disposal yard by truck. Each boiler will have one bottom ash bin with a storage capacity sufficient for about 40 hours of bottom ash production by the unit at BMCR when firing the design coal. The effective volume of each bottom ash bin is about 400m3 (8 m diameter by 21 m height). Each bottom ash bin will have the following facilities: two outlets will be located at the operation floor level of each bottom ash bin, one is associated with a telescopic chute for dry bottom ash and the other associated with a mixer for wet bottom ash. The telescopic chute’s capacity is 100 ton/hr. The mixer’s capacity is 100 ton/hr. One vacuum-pressure relief valve is mounted on top of each bottom ash bin for exhausting the pressure and vacuum in bottom ash bin. One BA bag filter is mounted on top of the bottom ash silo for the venting of the air. One high ash level indicator is fitted at the high position of bottom ash silo for sending the high ash-level message signal. One continuous-type ash-level indicator is designed for instant measuring bottom ash level height. Three air cannons will be installed for each bottom ash bin. The cooling water of the bottom ash cooler will come from closed circulating cooling water of the boiler house. The truck for bottom ash conveying will be provided by the Owner. The pneumatic fly ash removing system diagram is shown in the Drawing TA7502-MON-H02.

c. External Ash Transportation

320. The project’s external transportation for ash will be carried out on public thoroughfares. The ash system control adopts programmed central control.

I. Chemical Process of CHP5

1. Water Quality

321. The CHP5 plant will use the existing underground water source of the CHP3. The water quality from CHP3 water wells is shown in Table 6.16.

Table 6.16: Water Quality from CHP3 Water Wells

Parameter Unit Value

Hardness 0H 0.8

Alkalinity 0.7

Calcium ppm 12

Magnesium ppm 2

Sodium ppm 10

Potassium ppm 0.1

Chloride ppm 8

Sulfate ppm 16

Nitrate ppm 0

Silica ppm 8

pH 6.5


322. The chemical water consumption in CHP5 is shown in the following table.


Appendix 3-89

Table 6.17: Chemical Water Consumption Quality

Item Unit Amount Note

Water and vapor losses in the plant ton/hr 63 525x6x 2%

Water and vapor losses caused by blow-down ton/hr 16 525x6 x 0.5%

Water and vapor losses due to heating system ton/hr 7

Water and vapor losses caused by other systems and processes ton/hr 5

Make-up water for heat supply network ton/hr 339 16,938x 2%


323. With reference to international experience, related regulations, and requirements of the related boiler products in the power sector, the following water quality specifications should be used to ensure the safe, stable, and reliable operation of the boilers.

Table 6.18: Water Quality Required for Boiler

Name Item Indicator

Boiler Feed Water SiO2 ≤20μg/L

Steam

Conductivity (25°C) ≤0.3μS/cm

SiO2 ≤20μg/kg

Na ≤10μg/kg

Fe ≤20μg/kg

Cu ≤5μg/kg

Feed water (Alkali condition)

Hydrazine 10-30μg/L

Oil ≤0.3mg/L

Solved Oxygen ≤7μg/L

Fe ≤20μg/L

Cu ≤5μg/L

Positive Conductivity (25°C ) ≤0.3μS/cm

Hardness ≤1.0

pH(25°C ) 8.8～9.3 ( with Cu) 9.0～9.5 (without Cu)

Total carbonate of feed water (in terms of CO2) ≤1mg/L

Boiler Water (Treatment with Phosphate)

Salinity ≤50

SiO2 ≤0.25μg/L

Cl- ≤4mg/L

pH (25°C ) 9.0～10.0

Conductivity (25°C ) < 60μS/cm


2. Water Treatment System for Boiler Feed Water

324. The underground water will go through the following treatment processes in order to


Appendix 3-90

meet the required water quality: heating by raw water heater in the turbine shop; transport to the raw water tank; a raw water pump passes the water through a mechanical filter with activated carbon bed; the water is dosed to prevent scaling; a three-stage reverse osmosis system; transfer to a permeate tank; pumped through an ion-exchange unit; demineralized water is pumped to the demineralized water tank; and, from there, pumped to the main powerhouse. The detailed water treatment system diagram is shown in Drawing TA7502-MON-S01.

325. After considering the water consumption rate of the equipment and an appropriate margin of safety, the rated output of the primary demineralization system for the boiler feed water treatment system is designed to be 100 ton/hr. The water treatment system will require the following equipment: two sets of tanks for raw water with a capacity of 200 m3 and two sets of raw water pumps with a 150 m3/h capacity, anti-scaling chemical dosing equipment and two sets of reverse osmosis equipment with a capacity of 100 m3/h, one 200 m3 permeate-filter tank, two sets of permeate water pumps with a 100 m3/h capacity, mixed beds with diameter of 2000mm are to be provided with one in operation and the other in standby condition, one 200 m3 de-mineralized water tank and two sets of de-mineralized water pumps with 100 m3/h capacity each.

326. The output capacity of water softening equipment is designed to be 350 ton/hr. The system will require the following: one raw water tank with a capacity of 300 m3 and two sets of raw water pumps with 400 m3/h capacity, two sets of softeners with one in operation and the other in standby condition; one 300 m3 soft water tank and two sets of soft water pumps with a capacity of 400 m3/h.

327. To monitor the water quality and control the running of the system, some local instruments such as a pressure gauge, flow meter, conductivity meter and silicon meter will be built in the system. Programmable Logic Controllers (PLG) will be used to control the equipment in the system. Using a computer, monitor and a keyboard, it is possible to collect, handle, and record the information of the water treatment system and to automatically print any abnormal working conditions and sound an alarm if such conditions are detected. The chemical water treatment system is monitored in the control room of the water treatment workshop.

3. Other Water Treatment Systems

328. Cooling Water for the Auxiliary Systems. The recycling cooling water for the auxiliary systems is treated by adding anti-scaling and anti-corrosion chemicals.

329. Treatment System for Condensed Water. There will be a condensing water treatment system for treating the condensed water generated by the generator sets. Each generator set is provided with a de-ferrization filter that can handle condensed water. After passing the de-ferrization filter, the condensed water goes to the low-pressure heater.

330. Chemical dosing system for feed water. Chemical dosing equipment will be used to add chemical agents such as Helamin (not required ammonia, hydrazine and phosphate) into the feed water to prevent the equipment in the heating system and the pipeline from any damage by corrosion and scale.

331. Water and Steam Sampling System. An integrated water and vapor sampling system and the necessary online instruments will be used to monitor the condition of the heating system. An auxiliary control system will monitor and control the dosing system.

332. Integrated Treatment Station for Treating Industrial Wastewater. An integrated treatment station will treat the wastewater generated by the whole plant. Various kinds of wastewater are classified and collected and then transmitted to the treatment station. The wastewater is treated to meet the necessary quality standards before being put into comprehensive use.


Appendix 3-91

333. Water Treatment System for Cooling of Auxiliary Machines The auxiliary machine cooling water system of the CHP5 will have a closed-type circuit cooling water system. The closed-type circuit cooling water system uses de-mineralized water as the cooling medium and mainly supplies cooling water to such equipment with small water consumption and a high requirement for water quality such as the bearings of rotating machinery. The outlet pipes of the closed-loop circuit cooling water pump shall be connected to the sides of six boilers. The cooling water for the common equipment shall be separately piped from the closed-loop water pipes of the eight boilers to ensure the reliable operation of the generator sets.

334. Drainage System of the Plant. There will be one common drainage system for the plant. There are two sets of 40 m3 drainage tanks, two sets of 5 m3 drain water expanders and two sets of drainage pumps with a flow capacity of 20~50 m3/h installed. One is for operation and the other is for standby. The drainage pump will supply the preliminary feeding water to the boiler and deaerator water tank a starting the generator set. When the water quality is acceptable, the water drainage from the plant shall be allowed into the high-pressure deaerator by the drainage pump, or discharged to the specified boiler.

335. System of Make-up Water. A large portion of demineralized water will be directly supplied to the low-pressure deaerator as the make-up water for the heat supply network. One portion will go to the drainage tank of the common plant system and connected to the high-pressure deaerator by the main drainage pipes via the drainage pump for adjusting the level in the deaerator water tank; another portion will be directly connected to the air exhaust device for start-up of the drainage pump for water supply to the system when the starting and water make-up of the generator set is impeded.

336. Fire Sprinkler System of CHP5. The plant area is equipped with an indoor and outdoor hydrant system, automatic fire sprinklers, and a fire-fighting water supply system, with one fire-fighting pipe network set up in the plant area. The main areas covered by the fire-fighting water system include the steam turbine house, the boiler house, the transformer under the platform of the air cooling island, and the coal handling system. The fire-fighting water volume of the power plant is about 400 m3/hr. The fire-fighting water pumps are installed in the comprehensive water supply house, with two main electrical pumps. Additionally, to ensure oil area safety, a set of foam extinguishment systems shall be installed for the oil tank in the oil area. The fire-fighting auto alarm system, the smoke exhaust system and the building fire-fighting system are described in relevant professional specifications.

J. Electric System

1. Introduction

337. The following electric systems are proposed based on the needs of the power system: a 220 kV primary voltage interconnection system, two outgoing lines returning to the 220 kV substation, and the plant will be equipped with a 220 kV power distribution unit.

2. Regional Power Grid Plan

338. 220 kV Network Planning. To provide reliable interconnection to the 220 kV power system, interconnection lines with at least 700 MW loading capacity shall be constructed. During Phase I, construction of the CHP5 double circuit 220 kV interconnection line to the 220 kV switchgear of CHP4 has been proposed. Three units will be connected to the 220 kV GIS, but the existing CHP3 110 and 35 kV switchgears will remain without connection to the new CHP5.

339. During Phase II, construction of the 220 kV GIS will be extended and 2 additional 220 kV outgoing lines will be added to reinforce connection capacity to the system. Additional 220 kV lines also can be connected to the 220 kV switchgear of CHP4. However, connecting to the existing Erdenet 220 kV lines, which are currently connected to the 220 kV switchgear of CHP4, will be more effective.


Appendix 3-92

340. 110 kV Network Planning. To maintain a reliable UB 110 kV ring line, the existing 110 kV switchgear of the CHP3 will remain and shall be modernized during Phase II of the CHP5. The existing 110 kV double circuit line interconnecting to the CHP4 will be removed and one unit of the CHP5 will be connected to the modernized 110 kV GIS. The 110 kV outgoing double line to the Tuul River substation will remain.

341. To protect established 35 kV customers the existing 35 kV switchgear of the CHP-3 will be modernized to the more compact SF6 insulated switchgear.

342. To provide reliable interconnection between the 220 kV, 110 kV and 35 kV switchgears two 3 winding transformers with unit capacities of 100 MVA will be installed.

3. Automatic Dispatch

343. Dispatch Relationship. The power plant shall receive the dispatching guidance from the National Dispatching Center (NDC). Select operational data on the power plant will be sent to the NDC through the SCADA system, and the plant will accept and execute both the dispatching order of the NDC and its order of automatic generation control and reactive voltage control. 344. Configuration of Telecontrol System. A telecontrol system will be designed as a remote transmission unit. The collection and transmission of telecontrol information shall follow the principle of direct collection, direct transmission, and transfer of data to the Central Operator room, along with the transmission of related data to the NDC by two communication modes: through the dispatch data network and point-to-point.

345. Electric Energy Metering System. Currently, the measurement points are planned for the outgoing line side of the 220/110 kV circuit and at the high voltage side of the transformers. The examination points are planned to be located at the high voltage side of the main transformer and at the generator exit.

346. Automatic Generation Control. The electrical generator outputs synchronized ac electrical power, causing the generator and driving turbine to rotate at exactly the same speed (or frequency) as other synchronized generators connected into the common network. The basic speed/load governing equipment is designed to allow each unit to hold its own load steady at constant frequency, or to accept its share of load variations, as the common frequency rises and falls. The units will use either mechanical-hydraulic governing systems or electro-hydraulic systems.

347. Reactive Voltage Control. The most commonly used voltage control mode for generators is the automatic voltage regulation (AVR). In this mode, the excitation system helps maintain the power system voltage within acceptable limits by supplying or absorbing reactive power, as required. In disturbances where short circuits depress the system voltage, electrical power cannot be fully delivered to the transmission system. The fast responses of the AVR and excitation system help increase the synchronizing torque to allow the generator to remain in synchronism with the system. After the short circuit is cleared, the resulting oscillations of the generator rotor speed with respect to system frequency will cause the terminal voltage to fluctuate above and below the AVR set point.

348. Excitation controls are needed to prevent unacceptable conditions being imposed upon the generator. These controls are the over-excitation and under-excitation limiters within the AVR. The over-excitation limiter prevents the AVR from trying to supply more excitation current than the system can supply or the generator field can withstand. The over-excitation limiter must limit the excitation current before the generator field overvoltage protection operates. The under-excitation limiter prevents the AVR from reducing excitation to such a low level that the generator is in danger of losing synchronism, exceeding machine under-excitation capability, or tripping because it exceeds the loss-of-excitation protection setting. The over-excitation and under-excitation limiters are set to prevent the generator from operating outside its MW and MVAR capabilities.


Appendix 3-93

349. Phase Angle Monitoring Device. A set of phase angle monitoring devices will be installed in the CHP plant. The data gathered by the phase angle is transmitted via the power control data network to the monitoring master station.

350. Electricity Generation Load Control Substation. An electricity generation load control substation will be installed in the CHP plant. This substation system is connected with the network control main system for issuing and controlling the planned values.

351. Control Data Network. Electric power dispatching data network access equipment will be installed at the CHP plant. Its production control and management information will be connected to the two adjacent nodes of the control data network via a 2 Mbit/s channel nearby.

4. Main Electrical Connection

352. Phase I of the project will build three 150 MW units, each of which will be connected to the 220kV power system through its own 190MVA double-winding transformer. A generator circuit breaker (GCB) will be installed on each unit between its generator outlet terminals and the generator transformer. The GCB will be the point of synchronization. The 25 MVA unit auxiliary transformer (UAT) will connect between the GCB and the generator transformer. This will allow the unit auxiliary plant to be supplied from the UAT when the generator is not synchronized. The voltage at the generator outlet terminals will be 15.75 kV. A phase-isolated busbar (PIB) will be used for the connection from the generator to its transformers. An HV (high-voltage) standby power supply is provided from the 220 kV bus in the switchyard, using a 220 kV/6kV transformer with a capacity of 25 MVA.

353. The generator neutral point will be grounded through a grounding transformer. The 220kV grid will have its neutral point directly grounded. The neutral point of the HV winding of the generator transformer can be grounded through an earth switch and is fitted with a ZnO surge arrester and discharge gap protection. Depending on the operational mode requirements, the generator transformer neutral point can be directly grounded or left floating. The neutral point of the HV winding of the 220 kV standby transformer will be the same as that of the generator transformer.

354. The 220 kV switchyard has a dual-bus and is provided with a bus-tie circuit breaker. Two feeder bays for the two outgoing transmission circuits will be provided. The two transmission circuits are not within this scope of work. 355. For Phase II, the same scheme as above described will be designed.

356. The detailed grid connection system diagram is seen in Drawing TA7502-MON-D01.

5. Selection of Main Electrical Equipments

357. The rated capacity of the transformers will be selected according to the average temperature rise of the transformer winding in normal ambient temperature, not exceeding 65℃ after the maximum continuous volume of generators deducting the service power calculated capacity of units. According to the installation program, the rated output of the CHP5 is designed to be 820MW on the basis of 5x150 MW turbines plus the 1x70 MW backpressure turbine, in which the rated capacity of the primary transformer is 190 MVA. All transformers are three-phase transformers.

358. The 220 kV power distribution apparatus utilizes an open type outdoor power distribution unit. According to the requirement of the systematic power planning, the short-circuit current level of 220 kV equipment will be considered to be 50 kA.

359. The seismic oscillation peak acceleration at the factory site is 0.30 g (corresponding to a prime earthquake intensity of 8 degrees). At this point, the 220 kV circuit breaker is temporarily considered in the light of potting circuit breaker, while the power distribution unit is intended to adopt flexible conductor.


Appendix 3-94

360. The generator excitation mode is currently considered to be static excitation.

6. Auxiliary Power System

361. The auxiliary power system will be designed in phases. Phases I and II will have the same auxiliary power system scheme. In the following, the auxiliary power system for Phase I will be described, and accordingly, the system for Phase II can be replicated.

362. The HV auxiliary voltage will be 6kV; its neutral point will not be grounded. 6kV HV auxiliary power is to be supplied by the HV unit auxiliary transformer (UAT) connected as described above. There will be two unit auxiliary switchboards (A and B) for each unit connected to its UAT by a 6kV non-segregated bus. The two sets of auxiliary equipment for the boiler-turbine will be respectively connected to the two switchboards, and the standby power supply will be connected from the 6kV standby section supplied from the HV standby transformer. The 6kV side neutral point of the HV standby transformer will be not be grounded.

363. The 6kV electric supply system for the desulphurization system and DeNOx system is planned to receive its power supply from the 6kV transformers in the plant, while the low-voltage load will get its power supply from the two mutually spare low-voltage dry-type transformers.

364. In this Project, each unit is equipped with a quick start diesel generator set, to serve as the AC safety source of the unit, to guarantee that the safe shutdown of the unit will be provided with power when a blackout accident of AC service power occurs.

365. The high-voltage electric auxiliary system of 6kV utilizes neutral point grounding with resistance, and the low-voltage electric auxiliary system of 380/220V utilizes a neutral point solid ground.

7. Arrangement of Electrical Equipment

366. The main transformers, high-voltage local transformers, high-voltage start/spare transformers and other electric facilities will be arranged behind row A of the power house. The main transformers and the high-voltage side of start/spare transformers will utilize overhead lines to access the 220 kV power distribution apparatus. The low-voltage side of the main transformers utilizes an insulated bus to access the terminal of the generator. The 220 kV relay protection chamber is arranged within the 220 kV power distribution apparatus.

367. The 6 kV local electric distributions apparatus will be arranged in the steam turbine house, and be connected to the high-voltage local transformers and the low-voltage side of the start/spare transformers respectively via the common insulated bus. The 380/220V low-voltage local electric distributions apparatus will utilize the physically decentralized arrangement manner to be respectively arranged in the steam turbine house and in the centralized control building.

8. Direct-current (DC) System and AC Uninterrupted Power Supply (UPS)

368. The project will employ a 220V DC system. One bank of batteries and two sets of 100% high frequency switch rectifying charging equipment (battery charger) will be provided for each unit. The 220V DC system utilizes a subsection bus connection, which combines load control and power load, signaling and protection devices, for the DC oil pump, emergency lighting, etc.

369. This project will employ a digital static self-shunt excitation system for each unit, which will have an excitation transformer that is T-connected from the generator PIB and supplies the excitation current to the generator via thyristor-type rectifiers. The automatic voltage regulator (AVR) controls the generator operation conditions through changing the firing angle of the thyristor rectifying device.


Appendix 3-95

370. The excitation system mainly consists of an excitation transformer at the generator end, a thyristor rectifying device, an automatic voltage regulator, a de-excitation device, an over-voltage protection device, an excitation device, and the necessary monitoring, protection and alarming devices. The initial excitation power supply will be taken from DC system.

371. Each unit will have an AC uninterrupted power supply system (UPS), which will include a main cabinet (containing rectifiers, inverters, static transfer switches etc.), a bypass cabinet (containing bypass transformer, a voltage stabilizer, a manually-maintained bypass switches, diodes etc.) and a UPS Feeder Cabinet, etc. The static bypass switch switchover time is less than 4ms.

372. The UPS system will have a capacity of 60kVA with the normal power supply from the emergency MCC of 3-phase 380V±10% 50Hz. The bypass power supply will be from the LV unit auxiliary power system of phase-phase 380V±10% 50Hz. The DC power supply for the UPS will come from the unit 220V DC system. The AC output is single-phase 220V 50Hz. The operation mode of the UPS will be as follows: under normal operation, the power will be supplied from the 380V auxiliary power supply to the rectifier and inverted to single-phase AC 220V by the inverter then fed to the UPS feeder cabinet. When the auxiliary 380V power supply is not available, the power will be supplied by batteries to the inverters. In case the inverters are faulty or under maintenance or repair, the static bypass switch will automatically switch to bypass power supply for supplying power to the UPS feeder cabinet.

9. Electrical System Control and Protection

373. Control. The electrical system for each unit controls the electrical equipment by the computer supervision system, and employs the fieldbus technique to realize onsite signal acquisition. The elements controlled in the centralized control room include: the generator/transformer bank, the high-voltage station service work, the standby power supply, the low-voltage house transformer, the PC to MCC power cord, the safety source, the direct-current system, and the AC uninterrupted power supply.

374. The ESP employs a counterpart microcomputer control system from the ESP manufacturer. The coal handling system employs a pre-programmed automatic controller, with the control system being divided into three parts: external sensor, closed circuit TV system, and program control system.

375. Relay Protection. The generator/transformer bank and the high-voltage start/spare transformer protection use micro-processor based protectors, while the low-voltage local transformers and the high-voltage motors use micro-processor based integrated protection and monitoring devices.

376. The 220 kV circuit is established from the power plant to CHP4/Erdenet. Each line is to be equipped with two sets of full line and quick action main protection as well as back-up function. Both sets adopt OPGW fiber channel and dedicated optical fiber core. The distance skip and main protection share a common tunnel.

377. Each circuit breaker has a protection screen, including a synthetic reclosing device, a breaker malfunction protection, charge protection, a phase splitting control box, and so on. When the 220 kV outgoing line and the high voltage side of the main transformer have a segregation knife switch, a short lead protection should be configured. Each 220 kV bus is equipped with two sets of microcomputer bus protection. One fault recorder device is configured for the 220 kV wayside housing.

378. An information substation for protection and fault recording is planned for the power plant, which can communicate with the dispatching center. The security and stability control device needs to be studied separately.

379. Security System. The whole plant is equipped with security systems, the functions of which include a fire-alarm, firefighting linkage, an entrance guard, and fire telephone and broadcast.


Appendix 3-96

10. Communication in the Plant

380. The communication within the plant includes: a production management communication system, a production dispatching communication system (including a production dispatching system, a coal handling amplification/paging system) and wireless talk back communication system. The three parts are mutually back-upped and complementary, so as to form a safe and reliable plant-wide communication network of administration, production dispatching, and overhaul maintenance.

381. Production Management Communication System. This Project is equipped with a production management stored-program control exchange, configured with 300 user portals. The final system capacity is 1024 sockets.

382. Production Dispatching Communication System. The production dispatching system has a production dispatching stored-program control exchange, configured with 80 user portals. The final system capacity is 512 sockets.

383. The coal handling system is equipped with a set of coal handling amplification/paging system, which is configured with 40 stations, and can be expanded. 384. Wireless Talk Back (Walkie-Talkie) Communication System. The Project will have a wireless talk back (Walkie-Talkie) communication system, designed for 30 users for communications at the production locations far from the power house. 385. Commutation Equipment and Cable Network. The commutation equipment and cable network will have a distribution frame, a distribution box, a branch box, a communication cable, and the necessary subscriber terminal equipment. Currently, the production management system and the production dispatching system have one 1200 return wire distribution frame.

386. Power Supply for Communication System. Two sets of -48V/200A high-frequency switch power supply and two groups of -48V/500Ah valve-regulated lead-acid batteries are the communication power supply of this Project. The main engine of the coal handling amplification/paging system will use 220V A.C. power.

K. Plant Control System

1. General Description

387. The control system of the CHP5 plant shall be completely integrated based on modern distributed control systems (DCS) that shall provide the safe, reliable, and efficient operation of all units and the main station/common plant. The control system shall include the coordinated integrated control of the turbine and boiler, boiler controls, boiler auxiliary controls, turbine controls, turbine auxiliary controls, boiler and turbine protection, electrical system controls, ash and coal plant controls, flue gas desulfurization, water treatment plant controls, distribution heating system, and other common/station plant control systems.

388. It is mandatory that the control system hardware for the Boiler and Turbine Generator Plant be from the same manufacturer in order to achieve maximum system integration of the unit controls and standardized machine interface. All equipment shall be of a modern design quality, and commercially available from the system or equipment manufacturer.

389. Integrated DCS platform shall be flexible and handle the following:

Modulating Control

Sequential Control

Steam Temperature Control System

Burner Control System


Appendix 3-97

Feedwater Control

Boiler Combustion Control

Furnace Pressure Control Safety Supervision

Data Acquisition

Electric System Control

Balance of Plant Equipment Control

Flue Gas Desulfurization Control

Turbine Control

Turbine Supervisory Instrumentation

Emergency Shutdown

Coal and Ash Handling System

Soot Blowing System

Water Supply, Treatment and Chemical Dosing System

Wastewater Treatment System

Furnace Combustion Monitoring and Flue Gas Emission Control System

Plant Information and Management System

Data Linkage to Enterprise Resource Planning (ERP) Systems

Boiler Optimization

System Wide Efficiency Mapping

Training Simulation

390. The philosophy of the control, protection, and monitoring system shall be based on (but not limited to) the following capabilities and characteristics:

Maximum safety for the plant and plant personnel; Safe, reliable and efficient operation of the plant under all operational conditions; High overall control system reliability and availability; Plant is to be operated under all specified conditions (start-up, normal operation,

disturbance, and shutdown) automatically and/or under remote manual control; The malfunction of any component or loss of power supply shall lead to fail safe

condition triggering an alarm; The system is to provide accurate and reliable information to the plant operators,

maintenance staff, and management to allow decisions to be made and actions be taken to ensure the safe, reliable, and efficient operation of the equipment;

Redundancies shall be provided so that the failure of a single component shall not contribute to abnormal conditions, degrade the performance, or shorten the life of the plant;

Operator interface shall be LCD-based, with hardwired controls and indications limited to the most critical operator functions only;

All controls and instrumentation systems shall be designed, manufactured, and supplied by a single supplier in close collaboration with the plant manufacturers;

A system configured to provide a high level of plant automation with the ability for manual control when required;

Control and monitoring of entire plant from a centralized plant control room;


Appendix 3-98

All process control systems shall be microprocessor based with electrical transmission of all process measurements and control signals;

Control and monitoring facilities from local control centers; Control system hardware; microprocessor based, functionally distributed topology and

hierarchical control structure.

391. The DCS shall provide major and minor modulating control functions and sequence/on-off control function. To enable these requirements, the system shall provide control displays, process data acquisition and display, process data storage and retrieval, alarm handling, process reporting, control loop configuration, and database maintenance.

392. It is mandatory to use the standard platform for all plant control systems. If the system is based on architecture using different platforms, i.e., DCS-based controllers for the unit and auxiliary systems and programmable logic controllers (PLC) for common plant station (generator protection, generator excitation, high and low voltage digital motor protection and control, vary speed pumps, motor control and protection, etc.), then all control systems shall be fully and seamlessly integrated. The control system equipment shall comply with the detailed technical part of the specification. All control system architecture offered shall comply with the general requirements listed below:

It shall be possible to monitor and program the code associated with any unit or common plant station controller from a centralized engineering workstation located in the engineer's/programmer's room.

It shall be possible to display data from any unit or the common station controller at any of the LCD-based man-machine interfaces (MMIs) with a response time of less than two seconds under any normal or emergency operating conditions.

Alarms shall be handled at the MMIs by a common, integrated, and consistent alarm package for all units and the common plant station.

393. Critical control functions and drive/actuator switchboard motor controls shall be implemented via dedicated hardware to ensure availability under all conditions, including power supply failures to the control system. Typically, this shall apply to the following circuits:

Generator protection Turbine supervisory control and interlocking Emergency diesel generator control Auto synchronising control Fire services pumps Auxiliary power supply switchboard control and protection Motor/valve electrical and mechanical protection (process protection to be effected by

control systems).

394. A burner management sub-system (BMS) based on the same hardware used for other unit control sub-systems is preferred. However, in addition to the general and detailed control system hardware requirements of this specification, the BMS shall also be fully compliant with NFPA Codes 8502 and 8503.

395. All units and the plant station control system shall utilize a multi-level hierarchical control strategy. The hierarchy shall consist of individual components/loop control, functional group/subgroup control of related components, and unit control.

396. Design of the DCS shall be made to minimize the number of local control panels for each unit. Local control and indication panels however shall be supplied for the generator stator cooling water control, generator cooling, and makeup water control.

397. Chemical dosing, feedwater, and steam sampling systems shall be provided for monitoring water chemistry.


Appendix 3-99

398. A sampling system shall be provided for monitoring flue gas emission.

399. An overall network block diagram of the unit and station control system is shown in Figure 6.11. In this configuration, each unit shall be provided with a completely independent network and the station/common plant control system shall be provided with a completely independent network.

Figure 6.12: Plant Control System Configuration

Source: TA Team

2. Plant Control Center

400. The plant shall be supervised by the National Dispatch Center for electricity generation and Ulaanbaatar District Heating System for heat generation. The plant shall be controlled and monitored from a centralized plant control room (PCR) located in the control building. The centralized plant control room shall be occupied by staff 24 hours per day.

401. In addition to the centralized plant control center, a number of local control centers with different schedule requirements for staff shall be provided for major plant areas such as the ash and dust plant, the coal handling area, the HV switchyard, the water treatment area, etc.

402. The following local control centers shall not be permanently occupied:

Ash and Dust Plant

Electrostatic Precipitator

Flue Gas Desulfurization

HV Switchyard

Wastewater Treatment Plant


Appendix 3-100

Water Treatment Plant

Compressed Air Plant

Fuel Oil Storage and Transfer Plant

Diesel Generation Plant

403. Local control and monitoring facilities for the above plant areas shall be located at the respective control equipment rooms and shall be equipped with panel-mounted industrial computers and LCD screens capable of displaying and controlling the associated plant. These LCDs shall be based on industrial rack-mounted hardware rated at IP66 possessing touch sensitive screens and rack-mounted with drawable membrane keyboards with positive tactile feedback.

404. The coal handling plant control center shall be staffed 24 hours per day and hence require a control room with the following facilities:

Desktop LCD based operator workstations

Voice communication facilities which would include a telephone handset, VHF mobile radio system

Coal Plant CCTV system

405. Training System. The plant control system shall be equipped with training simulators for training plant operators and new staff. The training system shall have same hardware configuration as is in a real plant. The master computer shall be connected to the training system, which will allow creation of tasks and different conditions for steady, emergency state of the plant (boiler, turbine, generator, switchyard, coal and ash handling system, and auxiliaries).

406. The training system shall be able to connect with the real control system and update operation data to reflect more realistic process conditions. 407. Flue Gas Monitoring System. The flue gas monitoring system shall be connected to the DCS with adequate data bus or interface and be available for continuous monitoring and to create data base measurements.

408. The control and operation of the switchyard and the electrical equipment shall be done from the DCS. The electrical equipment’s microprocessor-based controllers, protections, etc., shall be interfaced with DCS system via appropriate protocols, like a SCADA system.

409. An Optical Ground Wire (OPGW) shall be used for communication between the power plant and the National Dispatch Center and the Ulaanbaatar District Heating System for grid operation data exchange, control and monitoring.

410. Boiler Soot-Blowing Control System. The boiler soot-blowing control system shall be interfaced with DCS. In normal operation, the system shall work in auto/remote operation. Local operation shall be enabled from local control panel. The soot-blowing control system will perform the following functions:

Soot blowers will be sequentially controlled

Manual initiation of automatic cycle

Manual blow of any selected soot blower

Blowing failure alarm

Forward and reverse traveling indication for long retractable soot blowers

Soot blower automaticly retracts when the motor overloads

Condensate draining system based on temperature indication


Appendix 3-101

411. Digital Electro Hydraulic System (DEH). The turbine manufacturer will provide a DEH control cabinet, a control oil system, local instrument and control equipment for turbine control and it shall be interfaced with the DCS. The DEH system will have the following functions:

Turbine speed regulation system (TSR). The speed control will be a closed loop control from run-up to rated speed. Auto or Manual speed-up control function can be selected by the operator.

The synchronizing demand will be sent to Automatic Synchronizing System.

Load Control System (LC): The turbine-generator output will be automatically regulated according to targeting load demand from coordination control system in DCS.

Load limiting system (LL).

Over-speed Control System (OPC).

Testing solenoid valves and turbine over-speed protection, etc.

412. The DEH hardware will be the same as the DCS hardware if possible. The DEH will be monitored and controlled from DCS operator station in the CCR.

413. By-Pass Control System (BPCS). Turbine by-pass system control functions will be implemented in the DCS. The by-pass system will incorporate pressure and temperature control valves to allow water spray to the steam prior to application to the condenser. The following control functions will be implemented:

Providing load ratio of the turbine by-pass system based on unit status (cold state, hot state, etc.)

Boiler start-up, turbine run-up, warm-up, maintenance constant speed, and connecting to initial load.

The BPCS can transfer the turbine by-pass system to the follow-up (tracking) mode in accordance with the main steam governing valve status.

The BPCS can limit the main steam pressure by increasing value and ratio.

The BPCS can adjust the by-pass system automatically per pressure curve based on unit operation mode (constant pressure or sliding pressure).

Increasing pressure, increasing temperature during boiler start-up.

414. Emergency Trip System (ETS). The ETS is a part of DCS. The system performs the safety functions of system protection for the plant’s major equipment such as its boilers, turbines, generators, etc.

415. For the turbine, once any one of the following trip signals received, the ETS will be initiated. The ETS will send a command immediately to close the main steam throttle valve.

Turbine overspeed

Thrust bearing metal temp. high-high

Loss of condenser vacuum

Low bearing LUB oil pressure

Generator main protection initiating

Loss of control oil

Operation of emergency turbine trip pushbutton in the CCR

Turbine-generator bearing vibration high


Appendix 3-102

Turbogenerator thrust bearing axial displacement high

Boiler MFT

Bearing metal temperature high-high

HP turbine exhausting steam pressure high

LP turbine exhausting steam pressure high

416. Turbine Supervisor Instrument (TSI). A whole set of turbine supervision instruments, sensors and transmitters required for safe start up, operation and shut-down of the turbine-generator will be furnished. This system will be connected to DCS.

417. The TSI equipment will be located in the electronic equipment room. The TSI will monitor the following:

Vibration of each bearing

Thrust bearing axial displacement

Eccentricity

Speed monitor

Expansion

Differential expansion

418. Electric Control System (ECS). The control and monitoring of the generator- transformer unit and the unit auxiliary power system will be implemented in DCS.

419. The control functions of Generator Excitation, Automatic Synchronizing System (ASS) and Automatic Voltage Regulation (AVR) will be achieved by independent devices. The start-up demand from the ECS will be sent to these devices via hardwire connection.

420. Motors will be controlled on the DCS and/or the switchboard and/or at the local control station. Once remote control function is selected by the R/L selector switch on switchboard, the circuit will be controlled by DCS. Current reading of all motors greater than 50kW will be displayed on DCS operator station. Motor start-up logic and interlock will be setup in DCS.

421. The DCS will be synchronized with the master clock once in every 24 hours. The Sequence of Events (SOE) Recording System will be synchronized with master clock once every 15 minutes. The master clock will be located in the CCR. Slave clocks will be located at various plant facilities.

422. SOE Recording System. The digital input of the SOE will be shared with DCS. SOE will be event-triggered to initiate a LCD flash display and print a hard log. Each SOE data acquisition can be performed in one millisecond to support event analysis. Events will be time-stamped, placed in the data archive and printed on dedicated alarm printer.

423. Limestone Handling Control System. Control and monitoring of the Limestone Handling Control System will be connected to DCS. Microprocessor-based controllers will be used for this system to ensure plant operation with safety and reliability. A local cabinet will be arranged inside the local control room and will be operated by an on-duty operator or through seamless integration with the DCS will allow full control and monitoring from the central control room. A panel-mounted, man-machine interface will be laid out on the front view of local cabinet for control or monitoring, maintenance or testing. Manual and automatic control modes for the operation of the plants will be used. The following control function will be implemented in DCS:

Performance control

Start-up/shut-down

Interlock and protection


Appendix 3-103

424. Fly Ash and Bottom Ash Handling Control System. The local PLC control units for the Fly Ash and Bottom Ash Handling Control Systems shall be connected to the DCS for operation and control.

3. DCS System Hardware Functional Requirements

425. The DCS systems shall provide comprehensive process monitoring, control functions, displays, alarms, calculations, data logging, data display, data storage and retrieval, and other functions for each generating unit and its associated auxiliary units at all stations described above.

426. It is required that all control and protection functions shall be implemented such that there is no reliance on loop communications for trip and control functions.

427. All hardware and software supplied under this specification shall be unit-based. It shall not be possible for a problem on one unit or any external system to impact the operation of any other unit. No unit box, workstation, processor, highway drop, etc., shall be shared between any two units. All information/processors and historical storage media shall also be supplied on a per unit basis.

428. The system shall be capable of being fully redundant from the input terminals, through the I-O processor, the controller processor, the output termination, power supplies, communication data highway, and operator man-machine interfaces.

429. The hardware shall be modular and uniform throughout to minimize the number of spares and types of test equipment and reduce the amount of time and training for operation and maintenance of the system.

430. All hardware supplied shall be suitable for an industrial environment. All core components such as CPUs, memory, I/O, bulk storage devices, and archival devices shall be rack-mounted in industrial cabinets.

431. Each unit and station control system shall possess the following main components:

DCS drops as required, each possessing:

- A dual redundant local data bus over which communications between the local DCS processors and I/O racks takes place;

- Dual redundant communications hardware connecting each drop to the dual redundant DCS data highway;

- Dual redundant processors or controllers; - Analogue and digital I/O modules with redundant capability (the BMS drop shall

possess some duplicate I/O); - Interfacing equipment providing bidirectional communications between the dual

redundant DCS data highway and any supplied PLC equipment; - Dual redundant DCS hardware and I/O interrogating power supplies and

associated distribution, monitoring and protection circuitry; - Specialized modules, racks and frames as required.

Dual redundant DCS data highway interconnecting all DCS resources;

Engineers/Programmers workstation (EWS);

Operator workstations equipped with LCDs, keyboards, mouse;

Other specialized DCS computing resources such as:

- Plant data storage and retrieval software; - Plant information application processors; - Alarm systems;


Appendix 3-104

- Reporting systems; - Gateways, bridges, protocol converters, printers, etc.

432. Control Processors Subsystem. Each controller subsystem shall be a microprocessor system of a common hardware base. All processors or controllers shall be capable of reporting their duty cycle as an analog tag in the database.

433. Each controller shall be configurable using standard software to provide process control algorithms and computational and logic functions required for full modulating and sequence control.

434. Each controller shall include its own dedicated input and output system and shall include full diagnostics of the input/output system operation. It is preferred that the ability to detect a single failed point on an I/O card be provided.

435. Each controller shall be capable of being independently configured to provide a nominated response to a failure.

436. Each controller shall shut down in a fail-safe and systematic manner in the event of a power failure. Automatic restart on resumption of power shall be configurable and will allow:

Closed loop controller power up in automatic Closed loop controller power up in manual Sequence control drives to be powered up in on, off, open, closed, or remain in current

position.

437. All controller subsystems shall include independent self-testing software that will continuously monitor the operation of all controller functions. These tests shall include tests of the computational facilities, memory, input/output, and communication links.

438. Memory shall be divided into two types: electrically programmable read-only memory (EPROM) or similar non-volatile memory and random access read/write memory (RAM). The controller processor firmware shall be in EPROM. All other software, including the database, shall be in RAM. RAM shall be backed up by batteries to prevent data loss from a power-failure. Memory shall be continuously checked for errors using CRC checks. System alarms shall be initiated when the errors are detected in the memory.

439. For redundant control processors, any single failure shall not prevent the processor transmitting on at least one highway.

440. The transmission time for the transmission of data between the process controllers shall be less than 100 msec on the same data highway and less than 200 msec where a bridge is used.

441. No loss of normal operating functions shall occur due to the loss of any one rotating device such as a hard disk.

442. System Redundancy Requirements. The system shall be designed such that a single failure in any redundant configuration shall not result in the loss of any functions necessary to carry out the normal operation of any part of the plant controlled or monitored by the redundant configuration. Redundancy of processors, disks, historical storage systems, and all equipment shall be as required to meet required system availability, but as a minimum, the following items shall be redundant:

Dual redundant local data bus over which communications between the local DCS processors and I/O racks occurs;

Dual redundant communications hardware connecting each drop to the dual redundant DCS data highway;

Dual redundant processors or controllers;


Appendix 3-105

Analog and digital I/O modules with redundant capability; Dual redundant interfacing equipment providing bidirectional communications between

the dual redundant DCS data highway and any supplied PLC hardware; Dual redundant DCS hardware and I/O interrogating power supplies and associated

distribution, monitoring and protection circuitry; Dual redundant DCS data highway interconnecting all DCS resources.

443. Data Highways. The systems tendered shall have fully-protected and segregated dual plant data highway cables connecting the DCS subsystems. Each DCS subsystem shall be connected via dual redundant data highway modules to the dual redundant data highways.

444. All plant data highways shall be duplicated to permit the transfer of information between the operator stations, input/output modules, process controllers, peripherals, and other components that make up the DCS. Both highways shall be continuously checked for integrity with any errors immediately reported to the operator and included in the shift review. It is preferred that the online/standby status toggles continuously between highways to prove their integrity. In the event of failure of transmission on any data highway transfer to the backup data highway shall be completely bumpless, automatic, and transparent to the user. An alarm shall be raised to indicate failure of the data highway.

445. The plant data highway shall be designed for quick and easy online connection and disconnection of any controller, processor, or node without affecting the operation of the rest of the system.

446. A failure of any controller, processor, or node on the plant data highway shall not affect the integrity of the plant data highway or communications between other healthy nodes on the highway. Any communication failure shall produce a system alarm and display a diagnostic message indicating the component that failed.

447. The plant data highway system shall incorporate error detecting and error handling techniques to resolve errors in transmission and to automatically cause retransmission of the information or transfer to the redundant system.

448. All plant data highways shall have permanent online monitoring continually analyzing the traffic. 449. Bridges and Gateways. The gateways or protocol converters shall be provided to interface between any station DCS and PLC systems low auxiliary control system.

450. Any gateway or bridge provided shall be redundant. All communications termination equipment shall be kept separate from signal and power termination equipment. Gateways and bridges shall have Surge Withstand Capability to IEEE C37.90.1 (unlimited). All gateways and bridges shall perform error checking and correction of all data transfers. 451. Functional Requirements and Cross Monitoring. Control system shall be designed, and commissioned for data highway interconnecting arrangement which shall provide the following functions:

Ability to access data from all DCS drops associated with the respective unit directly over the unit bus; and

Ability to access station plant data and graphics from the unit plant operator screens over the redundant bridge interconnection.

452. The following features are to be disabled from the DCS software configuration to prevent any operator mis-operation on the wrong unit:

It shall not be possible to recall operator screens and plant data from one unit system to the other unit system and vice versa for cross-unit monitoring or control.

It shall not be possible to recall station plant operator screens and plant data onto any unit plant system for cross-unit monitoring or control.


Appendix 3-106

453. DCS to Other Control Systems. Gateway or protocol conversion hardware and software shall be supplied, installed, and commissioned to allow dedicated high speed interfacing between the DCS and the station plant interfaces typically listed below:

Fuel Oil Unloading and Storage System Ash and Dust Handling Control System HV Switchyard Control System Wastewater Treatment Plant Control System Water Treatment Plant Control System Generation Plant Control System Compressed Air Plant Control System Coal Handling Plant Control System

454. Gateways shall permit bi-directional transfer of data to and from station plant based control systems over dual redundant high-speed serial connections. Gateways shall be sized to allow the transfer of all critical control and monitoring points for full control and monitoring of that station plant system, whilst maintaining an update time of one (1) second maximum from field input to unit or station plant operator screen. Response time from any operator action to field device shall be one (1) second maximum.

455. In addition, gateway or protocol conversion hardware and software shall be supplied, installed, and commissioned, if required, to allow dedicated high-speed interfacing between the DCS and any unit plant subsystem not directly able to communicate to the plant data highway, typically listed below:

Turbine Electro-Hydraulic Governor hardware (EHG) Automatic Synchronization System hardware (ASS) Automatic Excitation Regulator (AER) Electrostatic Precipitator or Fabric Filter Plant Hardware

456. Alternatively, such subsystems may be directly hardwired to the DCS I/O.

457. Information System Networks & Ethernet Bridges. An information system network based on Ethernet IEEE 802.3 using TCP/IP shall be provided for each Information Application Processor system provided for each unit and station plant DCS.

458. The Ethernet bridge shall also provide and interconnect a remote Ethernet LAN to allow remote access from the administration building or engineers’ office to each Information Application Processor for remote data querying and data retrievals.

459. Installed and System Expansion Requirements. All control and monitoring system input and output cubicles shall provide for an expansion capacity in addition to the installed spare capacity. The system shall be provided with a minimum 20% spare capacity for all aspects of the DCS or as specified below (whichever is greater):

Table 6.19: System Expansion and Spare Capacity

Installed and System Expansion Requirements Minimum Spare Capacity

Racked cubicle space, ready for insertion of new I/O cards 20%

Cubicle space for preformed cables and termination units 30%

Power supply ratings As required to provide power for the expansion capacity

Cubicle and panel space for mounting additional interfacing equipment such as interposing relays, power supply modules, etc.

30%

Number of spare digital I/O card MCB protected interrogation;Power supply circuits

As required to cater to all spare racked I/O slots


Appendix 3-107

Installed and System Expansion Requirements Minimum Spare Capacity

CPU I/O addressing capacity 50%

CPU application program memory 40%

Number of operator workstation addressable tags 50%

CPU application program cycle time/cycle slots 40%

Number of addressable distributed database tags 40%

Number of spare analog I/O point fused power supply circuits As required to cater for all spare racked I/O slots

Maximum network loading 40%

Storage devices 50%


460. This expansion capability might require the purchase of additional I/O modules, internal cubicle wiring, I/O cards, interposing relays, and running of cables, but shall not require upgrading of any DCS processors, operator workstation hardware or software, power supplies, or cubicles. 461. Spare Inputs and Outputs. The system shall be provided with a minimum of 20% spare cards, installed and terminated I-O points for each type used in DCS. A database entry shall be provided for each input/output with the database description field marked "SPARE."

L. Civil Engineering

1. Buildings and Houses

a. Main Power House Layout of the Main Power House 462. The three-row layout of the turbine room, combined deaerator and coal storage room and boiler room is designed for the main power house. The central control room is located between the turbine room and the boiler room. The total longitudinal length of the main power house room is 170.4 m. The total span of the main power house is 88.1 meters, of which 27 m is for the turbine room, 13.5 m for the combined deaerator and coal storage room and 47.6 m for the boiler house. The stokehold passage span of boilers is 7 meters.

463. The turbine room is divided into three floor levels at elevation 0 m, 4.5 m and 9 m, respectively. The turbine generator is installed at the 9 meter level with a distance of 11 m from its center line to Column Row A. A bridge-type crane is suspended under the roof truss, and the elevation of the rail top is 19 m. The first heat supply station is located at the left side of Axis 21. The floor elevations for the first heat supply station are the same as the turbine room.

464. The deaerator room is divided into four floor levels at elevations 0 m, 4.5 m, 9 m, and 20 m. The operating floor is located at the 9 meter level, while the deaerators are located at the 20 m level. The coal storage room is divided into three levels at elevation 0 m, 9 m and 37 m. The coal crusher is located at the 0 m level, the coal feeder is located at the 9 m level, and the coal conveyer is located on the floor at the 37 m level.

465. The central control room is located between the turbine room and the boiler room. Its dimensions are 17.2 m × 13.5 m. The electrical equipment is located at the 0 m level; the power distribution room is located at the 4.5 m level; the central control room is located at the 9.0 m level. The remaining two floors are used for the laying of electrical cables.


Appendix 3-108

466. The operating floor for the boiler room is located at the 9 m level, and one elevator for each boiler is installed for both goods and people to use.

Internal Transportation of the Main Power House 467. Horizontal transport: Operation and maintenance corridors will be located between the different floors where all the equipment in the turbine room is installed. A longitudinal corridor near to Column Row A and B that runs through the turbine room is also designed. Several exits at the 0 m level are designed for workers in the turbine room and boiler room. A longitudinal corridor in the coal storage room at 0 m level is designed for workers to repair coal crushers. A corridor in front of boilers at the 0 m level is designed for vehicles to drive. Main corridors that connect the coal storage room and the boiler room are designed for each set of turbines in the turbine room at 0 m level and at the operating floor. Fireproof doors are used at the 9 m level in the central control room to connect the operation floor in the turbine room.

468. Vertical transport. Three sets of stairways are designed to connect all floor levels in the main power house and two of them connect to the roof of the coal storage room. Several steel stairs are installed to meet the requirements of fire evacuation and daily operation and maintenance. Main equipment is transported by means of a lifting system through lifting holes located at each roofing floor and through the maintenance areas located in the turbine room. One elevator located in the side of each boiler is installed for workers to reach each maintenance platform at different floors. An enclosed stairway is located at the end of the central control building for workers to access each floor and/or roofs.

469. Fire Prevention and Evacuation. Six stairs are designed to be installed in the turbine house, boiler house and deoxygenating room, meanwhile several other steel stairs are also designed to be located in other necessary places to meet the requirements of fire prevention and evacuation. In addition, a fire protection and domestic water pool and a dry fire protection house are designed to be constructed to ensure effective fire prevention.

470. Sanitary Facilities. Water supply systems are designed to supply water both for industrial and domestic use. Restrooms and water sinks are installed in the central control building and other appropriate positions of the main power house. The domestic wastewater is designed to be discharged into the nearby municipal sewers.

Water Prevention and Drainage of Floors and Roofs

471. Floor Waterproofing and Drainage: The water washing method is considered to apply for the ground floor at the ±0.00 m level for the main workshops and the boiler house. The ground floors are designed with a slope to discharge the washing wastewater. The waterproof floor is designed for the operating floor areas underneath that the electrical control rooms are located. The water washing method is also considered to apply for the coal conveying corridors. The organized drainage ways are designed to apply for all the floors. 472. Roof Waterproofing and Drainage: The organized drainage ways with Grade II waterproofing are designed to apply for all roofs. The synthetic high-molecular waterproof roofs are designed to apply for the turbine house, boiler house, oxygenation house, dearator house and the coal storage house. The boiler roofs are profiled steel sheets with self-waterproofing functions.

Lighting and Ventilation 473. The main power house will use both natural ventilation and mechanical ventilation. The natural lighting is used as primary lighting and the artificial lighting is used as a supplement. Skylights will be installed on the roofs of the turbine house and the boiler house for partial lighting to improve lighting environment.


Appendix 3-109

Heat Supply 474. A heat supply system is planned to be installed in the central control room, the electrical room and other necessary rooms.

Decoration and Finishing Standard 475. The main decoration and finishing standard for the main power house is given in Table 6.20.

Table 6.20: Main Decoration and Finishing Standard for Main Plant

Section Turbine House/Oxygenation House Coal Storage House Boiler House

Interior Wall Scrub resistant coatings (ceramic tile wainscot)

Scrub resistant coatings (ceramic tile wainscot) ceramic tile wainscot

Exterior Wall Compound profiled steel sheet

Compound profiled steel sheet

Compound profiled steel sheet

Floor/ Ground Floor

Wear-resisting floor or quartz ground tile

Wear-resisting floor or waterproof &

wear-resisting floor －

Ceiling Scrub resistant coatings Scrub resistant coatings －

Source: TA Team

b. Auxiliary Buildings of Main Power House 476. The auxiliary buildings and auxiliary services of the main power house include a) the electrical buildings: the electrical house for the car dumper, the main transformer and the transformer for internal use, the stand-up and backup transformers, and the GIS; b) the water related buildings: the chemical water workshop, the industrial wastewater treatment workshop, the chemical feeding room of circulating water, the hydrogen storage station, the limestone workshop, the treatment house for wastewater from coal yard, the service water pump house, the cooling water tower, the circulating pump house for cooling water, the wastewater facility, and the deposition pool of mixture of coal and water; c) coal transport and dust removal buildings: the coal silo house, the coal conveying complex, the transfer station, the coal crushing house, the coal conveying corridor, the coal sampling house, the bucket wheel stacker declaimer end house, the car dumper house, the driving platform, the light trap house, the ash silo, the fan house, the ash removing complex, and the outdoor ash yard; and d) others: the oil tank, the oil pump house, the waste oil treatment facility, and the ID fan house.

477. The auxiliary buildings of the plant site include a) an office and complex with a floor area of 18,000 m2 that includes a garage, a power distribution room, a communication room, a safety, education and multi-function room, a cafeteria, bathrooms, and a night shift dorm; b) a warehouse; c) the mechanical workshop; d) the guard house; and e) a parking shed.

2. Concept Design of Structures

478. Major Technical Parameters for Design. Main structures at the CHP5 will be designed with careful consideration of the following design data.

Basic wind pressure: 0.45 kN/m2 (occurring once in 50-year) Basic snow pressure: 0.60 kN/m2 (occurring once in 50-year) Seismic fortification Intensity: Degree 8 Maximum soil freezing depth: 2-3 meters Maximum snow depth: 0.5 meters Underground water: not available


Appendix 3-110

479. Safety Level, Important Level and Seismic Fortification Intensity of Buildings. This Project is important and a large-sized power plant. The calculations of the structure designs for the main power house, chimneys, and other major buildings are based on seismic fortification intensity 8, and the seismic-resistance structuring measures are in compliance with the requirements for seismic fortification intensity 9. The calculations of the structure designs and the seismic-resistance structuring measures for all other buildings and houses are compliance with the requirements for seismic fortification intensity 8. 480. Main Power House. The horizontal column distance for the main power house is 8 m, and the longitudinal column distance varies from 7 m to 27 m. Double rows of steel columns between Axis 8 and Axis 1/8 and between Axis 15 and Axis 1/15 with a distance of 1.2 meters are designed to avoid damage from expansion caused by hot weather and contraction caused by cold weather. The local seismic fortification intensity is Degree 8.

481. The primary equipment of the main power house includes the turbine, boiler, generator, coal bunkers, dust collector, ID fan and blower, and oxygen remover. The structure of the main power house will be a steel structure, including steel columns, steel beams and steel truss roofs. The foundations of the steel columns will be independent cast-in-site reinforced concrete structures below the ground level. The steel sheets will be embedded on the tops of the reinforced concrete foundations above the ground level. The embedded steel sheets will be connected with steel columns through qualified welding and/or partial anchor bolts. The surrounding structure will use ceramist concrete hollow blocks with a thickness of 300 mm for exterior walls and 250 mm for interior walls. Crane beams and coal buckets will be steel structures. Boiler cradles are required to be steel structures that will be designed and supplied by qualified boiler manufacturers.

482. The ground floor of the main power house will be case-in-site terrazzo floor. The floor with electrical cable intercalated bed will be cement mortar floor. The floor for operation purpose will be tiled floor. The external doors will be electrical roll-up doors. The interior doors will be multicolor steel plate doors. The fire doors will be used in all the necessary locations depending upon the firefighting requirements. Exterior windows will be multicolor steel sheet windows. Exterior walls will use light-color acrylic coatings, and interior walls will use scrub resistance coatings. The central control room will have a granite floor, aluminum alloy doors and windows, aluminum fictile plate suspended ceilings, and tiled floor. 483. Flue Gas Pipe and Chimney. There are two sleeve type chimneys each with a height of 250 m. The chimneys will be made of an anti-corrosion reinforced concrete structure with a steel inner cylinder and an outlet diameter of 7.8 m. The external cylinder will be cast-in-site concrete tubular structure. Acid-resistant ceramsite blocks will be used for inner lining, hydrophobic perlite insulation slabs will be used for heat insulation layers, and acid-resistant mortar will be used for connections between the two materials.

484. The supports for the flue gas pipes will be reinforced concrete structures, and the foundations of the columns will be an independent reinforced concrete base with a burial depth of 3 m. The bottom and top slabs of the flue gas pipe are cast-in-site reinforced concrete structures. Acid-resistant ceramsite blocks will be used for inner lining, hydrophobic perlite insulation boards for heat insulation layers and brick masonry with MU7.5 type for exterior walls. 485. Coal Yard, Coal Transferring Building, Coal Conveying Corridor. The size of the coal yard is 160 m x 500 m with a total area of 8000 m2, of which 4000 m2 will be used for Phase I and the remaining 4000 m2 will be used for Phase II. A windbreak of brick masonry will be constructed at the ends of the coal yards.

486. A cast-in-site reinforced concrete frame structure will be used for the coal transferring buildings. A cast-in-site reinforced concrete frame structure and independent cast-in-site reinforced concrete foundations will be used for the multi-story coal crushing house.

487. A steel structure will be used for the coal conveyor corridors. The main body of the


Appendix 3-111

coal conveyor corridors is steel truss. Steel beams and cast-in-site reinforced ceramsite concrete slabs, and glass fiber reinforced cement slabs will be used for the side walls and roofs.

488. Bottom Ash Storage and Fly Ash Silo. Each boiler will have a combination bottom ash bin at the bottom of the boiler. The bottom ash bin will be a steel structure. The effective volume of each bottom ash bin is approximately 400 m3 with a diameter of 8 m and a height of 21 m. There are 3 fly ash silos with a diameter of 15 m and a height of 24 m. Cast-in-site reinforced concrete cylindrical structure and flat-slab type reinforced concrete foundations will be used for the ash silos. 489. Water Treatment Building. Cast-in-site reinforced concrete structures and reinforced concrete bar foundations will be used for water treatment buildings. Water-proofed, reinforced concrete will be used for all relevant tanks and water treatment structures. Furthermore, the thickness of the concrete protection layers for steel bars shall be at least 50 mm to avoid concrete erosion.

490. Warehouse, Mechanical Workshop, Office, and Guard House. The office and complex will be a 10-floor-building. Its span is 15 m, while its length is 120 m. Its total floor area is 18,000 m2. The office and complex will be a cast-in-site reinforced concrete frame structure, including a cast-in-site reinforced concrete foundations, columns, beams, and slabs. Similarly, the warehouse, mechanical workshop, and guard house will also be cast-in-site reinforced concrete frame structures. The dorms, eatery and bathrooms will be located in the office and complex.

M. Water Supply and Drainage System and Cooling Facility

1. Water Source

491. Fresh well water and domestic water is available to the site. Water has been piped to the site from a well field. The water is to be stored and treated as appropriate for the following uses.

Domestic water from the municipal water system can be used for drinking water, sanitary and meal rooms, etc.

Industry service water will be circulated through the power station to meet the requirements for wash down, the mechanical workshops, the supply to the demineralisation water treatment plant, for dust suppression, etc.

Fire fighting water will be circulated through the power station to meet fire fighting requirements.

Demineralized water for the power station’s requirements for high purity water will be produced by an ion exchange demineralization plant that will be provided.

2. Circulating Water System

492. The secondary circulating system with a natural-ventilation cooling tower will be used for this project. The circulating water flow rate is shown in the following Table 6.21.


Appendix 3-112

Table 6. 21: Circulating Water Flow Rate (Summer, ton/hr)

Unit Condensing Steam Volume

Circulating Water Flow Rate Oil Cooler Air Cooler Subtotal

1 300 16,500 500 240 17,990

2 300 16,500 500 240 17,990

3 300 16,500 500 240 17,990

4 300 16,500 500 240 17,990

5 300 16,500 500 240 17,990

6 300 240 17,990

Total 1500 82,500 2,800 1,440 86,740

Note：i) it is estimated on condensing condition; ii) Ratio of circulating water flow rate to condensing steam flow rate is 55; and iii) 6# unit is backpressure turbine.


493. The circulating water system will be configured with a common header. The circulating pump house, the make-up water pump house, the cooling tower and related pipelines will be arranged on site. Each turbine will have two circulating pumps. Each pump will have a capacity of 50% of the designed circulating flow rate for each turbine. A total of ten circulating pumps will be installed, of which six pumps will be installed for Phase I and four pumps for Phase II. Phase I will have two cooling towers with 4,500 m2 cooling surface each. Phase II will have one cooling tower with 6,000 m2 of cooling surface.

3. Make-up Water System

494. The water will be refilled for cooling tower make-up water, boiler and heating system, industry water system, domestic water system, fire fighting water system, etc. The detailed water balance is shown in Table 6.22 and Table 6.23.

Table 6.22: Water Consumption for CHP5 (From 15th May to 15th September)

User Demand(ton/h)

Recover(ton/h)

Water Consumption(ton/h)

Domestic Usage 10 8 2

Cooling tower Evaporation 1167

1945 735 1210 Fly water 43

Blowdown 735

Boiler and heating network 76 30 46

Air-conditioning system 8 4 4

Industry circulating water system 900 900 0

Spray water for coal conveying system 10 5 5

Contingency (5%) 120 120

Washing water for coal conveying system 12 8 4

Spray water for coal yard 20 20

Spray water for ash yard 25 25

Water for humidifying dry ash 15 15


Appendix 3-113

User Demand(ton/h)

Recover(ton/h)


Floor and equipment cleaning 5 5

Water for grass land and road 4 4

Total 3130 1672 1456


Table 6.23: Water Consumption for CHP5 (From 15th September to 15th May)

User Demand(ton/h)

Recover(ton/h)


Domestic Usage 10 8 2

Cooling tower Evaporation 735

1179 399 780 Fly water 45

Blowdown 399

Boiler and heating network 430 30 400

Air-conditioning system

Industry circulating water system 900 900 0

Spray water for coal conveying system 10 5 5

Contingency (5%) 90 90

Washing water for coal conveying system 12 8 4

Spray water for coal yard 20 20

Spray water for ash yard 25 25

Water for humidifying dry ash 15 15

Floor and equipment cleaning 5 5

Water for grass land and road 2 2

Total 2,668 1,332 1,344


495. The water consumption will be 1456 m3/h in summer and 1344 m3/h in winter. The annual total water consumption will be 8.1 million m3/a.

4. Service Water System

496. In 2007 the total available flow rate of the wells was evaluated to be 36,122.4 m3 per day (for 24 hours). This existing water supply system can be used for the CHP5 and there is no need to establish a new water supply system. The existing water supply system can serve as the water source of the industrial service water system. Water for chemical water treatment and make up water for cooling tower is provided by the service water pump that meets the requirement of the CHP5. The domestic water supply system is fed from city water utility. The detailed water treatment system diagram is seen in Drawing TA7502-MON-S02.

497. The fire cistern and the service water tank are combined. Two fire cisterns with a capacity of 1,000 m3 will be built. Three service water pumps, each with a capacity of 50% of total capacity is installed in the comprehensive water pump room.

5. Water Supply and Drainage of the Plant

498. The water supply and drainage systems include: the domestic water supply; the storm


Appendix 3-114

water drainage, the domestic sewage, the wastewater drainage; and, the domestic sewage treatment.

a. Domestic water supply

499. Domestic water is distributed to the domestic water tank via an urban water supply pipeline and then to the water supply points by boosters using automatic frequency converting water supply equipment.

b. Drainage system

500. The drainage system consists of storm water drainage, domestic sewage, and operation wastewater drainage. A separate discharge system that includes the domestic sewage pipeline, the production wastewater pipeline and the storm water pipeline, will be used for the drainage system.

501. Domestic sewage is collected and discharged to the domestic sewage treatment plant through sewers and then to the industrial wastewater sewers after meeting the discharge requirements. Wastewater treatment includes acid-alkali wastewater and washing water. Acid-alkali wastewater is discharged to the industrial sewers after being treated and meeting the requirement. Industrial wastewater is recycled after being treated. Storm water is collected into a ditch and discharged to a sort of wetland through storm water sewers.

c. Coal contaminated water treatment system

502. Coal contaminated water comes from washing coal transportation equipment and from the coal yard when it rains. Washing water and storm water are collected in the sedimentation tank and discharged to the coal contaminated water treatment facility by pumping after pre-sedimentation. Coal contaminated water is discharged to the clean water tank for recycling after clarification and filtration.

d. Oily wastewater drainage system

503. Oily wastewater comes from (i) turbine room washing water and equipment washing; (ii) oil tank washing; and, (iii) the transformer area. Oily wastewater is collected in the oily wastewater regulating tank and discharged to the recycling water tank after being pumped into the oil-water separator by a progressing cavity pump for treatment.

6. Hydraulic Construction Design

504. A comprehensive water pump house will be constructed. The planed dimension of the bottom structure headroom 45 m long x 12 m wide and the structure is cast-in-place reinforced concrete; the plane axial line of the upper structure is also 45 m long x 12 m wide, and with a height of 6.5 m. The upper structure is a cast-in-place reinforced concrete frame structure with a cast-in-place roof plate and masonry wall enclosure. A power distribution room and a control room will be constructed at the end of the upper structure of the pump house with the plane axial line 12 m long x 5 m wide and a height of 4.5 m. The power distribution room and the control room are a cast-in-place reinforced concrete frame structure with cast-in-place roof plate and masonry wall enclosure.

505. The domestic sewage treatment station includes two wastewater treatment facilities, one wastewater regulating tank, and one clean water tank. The wastewater treatment facility is an underground reinforced concrete structure with the single plane size of 9.7 m long x 7 m wide with a depth of 4 m; both the wastewater regulating tank with the headroom size of 12 m long x 8.5 m wide with a depth of 7 m; and, the clean water tank has a headroom size of 6 m long x 6 m wide with a depth of 4 m are all underground reinforced concrete structures.

506. The coal contaminated water treatment station includes a coal contaminated wastewater treatment room, a sedimentation room, two sedimentation tanks and a clean water tank. The treatment room is a reinforced concrete structure with cast-in-place a


Appendix 3-115

reinforced concrete roof as well as the masonry wall enclosure. The plane axial line is 36 m long x 12 m wide and a height of 8 m. The sedimentation room is reinforced concrete bent structure with cast-in-place reinforced concrete roof and masonry wall enclosure. The axial lime is 48 m long x 20 m wide and a height of 8 m. Two sedimentation tanks sharing the same wall will be placed in the sedimentation room. Both tanks are underground reinforced concrete structure with the single plane headroom of 42 m long x 8 m wide and a height of 6 m.

507. The clean water tank which is an underground reinforced concrete structure with the headroom size of 12 m long x 6 m wide is located in the wastewater treatment room.

508. The oily wastewater treatment station includes an oil-water separator room and a wastewater regulating tank.

509. The oil-water separator room is a reinforced concrete frame structure with cast-in-place reinforced concrete roof and masonry wall enclosure. The plane axial line is 10 m long x 8 m wide and a height of 7 m.

510. The oily wastewater regulating tank that is an underground reinforced concrete structure with the headroom size of 5 m long x 5 m wide and a depth of 5 m and is located in the oil-water separator room.

511. In addition, plans call for two industrial fire cisterns with a capacity of 1000 m3, a reclaimation water tank with a capacity of 400 m3, a domestic water tank with a capacity of 200 m3 and two oil tanks against accidents with capacity of 100 m3. All facilities are designed to be cast-in-place reinforced concrete underground structures.

7. Water Conservation Measures

512. The Project is located in UB urban area with scarce water resources. To meet the requirements of sustainable economic development and long-term power construction plan, water conservation and environmental protection are required. Water conservation measures to be taken are as follows:

A dehydrator will be installed in the cooling tower of the circulating cooling system to reduce air blowing loss.

Recycling of water drained from the heating equipment and the pipeline both in working condition and accident condition. Temperature regulating valves will be installed on the drainage pipelines not only for controlling water temperature but also for saving water.

Wastewater from the water feeding system and condensate polishing system is recycled after industrial wastewater treatment.

Biocide, scale inhibitor and sulfuric acid are applied to treat circulating cooling water thus the concentration rate is increased and the discharge capacity of circulating cooling water is reduced.

The discharged cooling water of the auxiliary circulating water system is used as the cooling water and process water for the desulfurization system.

Water usage of the coal transport system is mainly for trestle bridge washing and floor washing of the transfer station. Washing water is sent to the sedimentation tank and is recycled for washing, spraying or dust removal.

The slag removal system uses mechanical slag removal.

Pneumatic conveyors are used for internal dust removal system. Dry dust is discharged dry. Trucks are recruited for transport so that the water consumption is reduced.

The graded utilization principle is applied to the insufficient part of process water.


Appendix 3-116

Wastewater is discharged to the recycling tank after treatment and is used for humidification of dust removal.

Domestic sewage, oily wastewater and industrial wastewater are discharged to the recycle tank for road washing, dust removal, and dust yard spraying.

Coal contaminated wastewater is collected in the treatment station by a separate drainage system and is used for coal yard spraying, dust removal of coal transport system.

Water conservation tap and controls are used for restrooms to reduce domestic water consumption.

To increase the recycling rate of water, recycle as much water as possible.

N. Ash Yard

513. The ash yard is located 0.5 km away from the west site of the CHP5. Trucks will be used for transporting ash. The external ash transport road will be a concrete pavement road with the width of 7 m and sub-grade with the width of 8.5 m. The internal ash transport road will be of clay-bound macadam pavement with the length of 0.5 km, pavement width of 6.5 m and subgrade width of 8 m.

1. Ash Dam and Drainage Measures

514. The elevation of the top of the ash pile is 1,375 m, while the height of the ash pile is 50 m. The storage capacity is 1.5 million m3, which can meet the ash storage requirement of the generator unit for years. The dam is constructed at the lower-middle part of the cleft downstream in the initial stage. The initial dam is a rolled soil dam to be constructed with clay from the ash yard.

515. To drain storm water collected in the ash yard in time, a drainage skewed slot will be installed at the bottom of the cleft from upstream to downstream. This subdrain will be connected to the stilling pool that is at the skewed slot downstream section for the downstream of the skewed slot and initial dam section. Both the drainage skewed slot and subdrain are cast-in-place reinforced concrete structures. The length of the skewed slot is 600 m while the length of the subdrain is 300 m.

2. Seepage Control

516. To prevent seepage from polluting the underground water and downstream environment, a composite geo-membrane is to be installed in the bottom of the ash yard as well as on the inside of the dam slope to stop seepage in the ash yard into the underground water. Earth with thickness of 0.3 m is placed on the surface of geo-membrane.

3. Operation and Management of the Ash Yard

517. The dry ash storage operation involves stratifying and rolling the ash, soil covering and reclamation. Ash slag is piled up from the initial dam to the end of the ash yard zone by zone, and is rolled layer by layer. An ash dam external slope will be formed when the ash pile exceeds the height of the initial dam. A protecting filtration structure that consists of a prefabricated concrete surface protector, sand cushion and geotextile will be constructed to overcome the increasing of the slope.

518. An ash managing station located on the platform near the ash yard with the ash transport path will be installed. Offices, garages and boiler rooms will be built in the ash managing station with the construction area of 250 m2; an underground reinforced concrete tank with the capacity of 200 m3 and a car wash platform will be constructed in the station.


Appendix 3-117

519. A bulldozer, roller and a spray wagon are employed for the rolling equipment in the ash yard.

4. Environmental protection measures

520. The following environmental protection measures will be taken:

A composite geo-membrane will be placed on the bottom of the ash yard as well as on the inside of the dam slope to prevent seepage from the ash yard.

Water will be sprayed to ensure that the water content of ash pile is sufficient to increase the cohesion between coarse ash particles. Water used for spraying is from the clean water tank in the managing station and transported to the ash yard by spraying wagon. Water from the stilling pool can also be used as spraying water.

The ash pile is divided, zoned and delaminated by rolling to reduce the exposed surface. Approximately 0.3 m of covering soil will be placed on the surface of each ash pile when it reaches permanent piling elevation.

Sealed trucks will be sought for ash transportation in order to reduce fly ash along the road and prevent secondary dust pollution. Car washing platforms will be built at the exit of the plant as well as at the ash managing station. Ash transport vehicles and operating equipment will be washed regularly.

The underground water of the ash yard and the secondary fly as yard will be monitored regularly.

O. Fire Fighting System

521. The fire fighting system includes a water fire fighting system, a gas fire fighting system, a foam fire fighting system, fire extinguishers installations, construction of fire fighting pond, fire pumps and a fire pipeline network. The water fire fighting system is responsible for the fire fighting of the main plant, auxiliary and associated buildings, the oil tank area, as well as the fire fighting water of cooling water and transformer water spray, automatic spraying or spraying system of the equipment in the main plant, automatic spraying system of coal transport system.

522. Fire fighting measures for key buildings and equipment are as follows: there will be an outdoor fire hydrant system installed at the plant; an indoor fire hydrant system will be installed in key buildings; a water spray system will be used for the transformer and oil system; a fixed foam fire extinguishing system will be used for the oil tank area; a fixed or semi-fixed automatic gas fire fighting system will be used in the key equipment room of the central control building; and, portable fire extinguishers will be used as well.

523. Various methods are utilized in fire fighting design. Different fire fighting methods shall be used for different objects to ensure the fire loss is minimized.

1. Water supply of fire fighting system

524. The fire hydrant system and automatic spraying system share the same system. Make up water is the main water source for the fire fighting system. Maximum water consumption of fire fighting for the main plant is 468 m3/h. Two industrial fire water ponds with a capacity of 1000 m3 and the minimum water storage of m3 that meets the requirement of one fire are to be constructed. The time for refilling water shall be less than 48 hours.

525. Two electric-drive pumps, each with 50% of total capacity, a diesel-drive pump with 100% of total capacity and constant pressure equipment (which includes two constant pressure pumps and one diaphragm expansion tank) are installed in the comprehensive water pump room for the fire fighting system.


Appendix 3-118

526. A high-pressure hydraulic loop network for firefighting is formed at main plant, furnace back area and coal storage area. Indoor and outdoor fire hydrants are connected to this network.

527. A water spray system is installed for the transformers, the high-voltage transformers, and standby transformers. A retainer oil pit will be built for oil discharging to prevent fire from spreading when transformers are on fire. A water spray system will be installed for the oil system in the main plant such as the oil storage tank, hydrogen sealed oil devices, turbine lubricant tank, and detergent oil tank; water spray is employed for the boiler burner, air pre-heater, coal crusher lubricant station; automatic water spray system is used for the backup diesel generator.

528. A water curtain will be installed at the joints of the coal transport trestle bridge, transfer station, coal crusher room and main coal storage. An automatic wet water spray system is installed for the trestle bridge. Fire hydrants and water curtain will be used for the coal mixing tank.

2. Gas Fire Fighting system

529. A clean gas fire system will be utilized for the project. A gas fire fighting system will be installed in the main control room, the computer room (engineer station), the electronic device room and the relay room to protect important electronic device and computers; a total flooding extinguishing and combined distribution system is utilized.

P. HVAC

530. Heating and ventilation design includes the main plant and auxiliary buildings, heating, ventilation, air conditioning, dust removal and vacuum cleaning systems for the auxiliary buildings.

1. Heating

531. The outdoor design temperature for the project is -39°C. There are 240 heating days per year when the daily average temperature is below 5°C. The central heating system is designed for plant production, assistance production, and auxiliary buildings. Hot water with temperature of 110/70°C is the heat medium.

532. The main plant will use a radiator heating system supplemented by a fan heating system.

533. To reduce the negative impact of the “chimney effect” on the space heating in boiler house, measures shall be conducted for design, operation management with the manner of safe, reliable and energy conservation are as follows:

To reduce cold air infiltration, the lower part of boiler room and stairs to the operating platform shall be sealed.

Avoid boilers sucking air directly from outdoors during winter

Install hot air curtains for doors that open frequently

2. Ventilation

534. Natural and mechanical ventilation are used to remove the exhausted heat and moisture in the turbine room.

535. With an open layout for levels above the operating level in the boiler room, natural ventilation and mechanical air exhausting are. Fresh air enters boiler through windows at the bottom level and exhausts from the blower at the top of boiler room after absorbing heat emitted from equipment and pipeline.


Appendix 3-119

536. Individual louvers will not be installed in turbine and boiler rooms to reduce cold air infiltration in winter. Construction windows will remain open in summer for air intake.

537. A mechanical ventilation system will be installed in the 6 kV power distribution room and in the low-voltage power distribution room with indoor dry type transformers in the turbine room; a positive pressure ventilation system of mechanical air intake and exhaust is employed for the power distribution room located at boiler room or back of the furnace; a cooling ventilation system is designed for air cooling the power distribution room. Natural ventilation and mechanical exhausting are employed for the remaining power distribution rooms.

538. A mechanical ventilation system will be installed in workshops that contain flammable, explosive and hazardous gas, in electrical equipment rooms and for underground construction.

3. Air conditioning

539. Rooftop air conditioning units and air supply/return air conditioning system will be used for the air conditioning system in the boiler, turbine and electrical device rooms. The condenser for the chiller will be located outside; an air handling unit is located in the air conditioner room. High temperature water is used for heating during winter. The design parameters of the air conditioner room are: a room temperature of 26 ± 1 °C and a relative humidity of 50 ± 10% in summer; a room temperature of 20 ± 1 °C and a relative humidity of 50 ± 10% in winter.

540. Split air conditioners will be employed for dispersed control rooms and other rooms that require comfortable temperature for personnel.

4. Dust removal and vacuum cleaning

541. A mechanical dust removal system shall be installed at the transfer station, at the coal crusher room and at the coal storage level.

542. A water spray system will be installed at the wagon room and at the original coal field.

543. A vacuum cleaning system shall be installed in the boiler room for coal ash cleaning as well as coal storage and coal crusher room cleaning.

5. Heating pipeline network

544. A combination of a forked structure, an integrating pipe bracket and a direct-bury installation will be used for the heating pipeline network. A dual-pipe, closed-system will be used for the heating pipeline network. A high-density polyethylene cover and hard polyurethane foam prefabricated insulating pipe shall be used for the heating pipeline network. A compensator will be used when natural compensation cannot meet the thermal compensation requirement.

Q. Flue Gas Dust Removing, Desulfurization and Denitration

1. Electrostatic Precipitator (ESP)

545. Each generator unit will have an ESP with parallel gas paths. Each path will consist of four electric fields in series for the collection of fly ash. The ESPs will have a dust collection efficiency of not less than 99.6%, while firing coal with the ash content of 10%.

546. Principal of the ESP. The ESP functions by electrostatically charging the dust particles in the gas stream. The charged particles are then attracted to and deposited onto plates or other collection devices. When enough dust has accumulated, the collectors are shaken to dislodge the dust, causing it to fall with the force of gravity to hoppers below. The dust is then removed by a conveyor system for disposal or recycling.


Appendix 3-120

547. Electrostatic precipitation removes particles from the flue gas stream of stack. Six activities typically take place: i) Ionization - Charging of particles; ii) Migration - Transporting the charged particles to the collecting surfaces; iii) Collection - Precipitation of the charged particles onto the collecting surfaces; iv) Charge Dissipation - Neutralizing the charged particles on the collecting surfaces; v) Particle Dislodging - Removing the particles from the collecting surface to the hopper; and vi) Particle Removal - Conveying the particles from the hopper to a disposal point.

548. Designing a precipitator for optimum performance requires proper sizing of the precipitator in addition to optimizing precipitator efficiency. While some users rely on the precipitator manufacturer to determine proper sizing and design parameters, others choose to either take a more active role in this process or hire outside engineering firms.

549. Precipitator performance depends on its size and collecting efficiency. Important parameters include the collecting area and the gas volume to be treated. Other key factors in precipitator performance include the electrical power input and dust chemistry. During the design stage the following factor will be focused on:

Precipitator sizing: The sizing process is complex as each precipitator manufacturer has a unique method of sizing, often involving the use of computer models and always involving a good dose of judgment. No computer model on its own can assess all the variables that affect precipitator performance.

Collecting Efficiency: Based on specific gas volume and dust load, calculations are used to predict the required size of a precipitator to achieve a desired collecting efficiency.

Power Input: Power input means the voltage and current in an electrical field. Increasing the power input improves precipitator collecting efficiency under normal conditions.

2. Desulfurization Facility

550. Limestone Desulfurization inside CFB. An FBC Boiler will be utilized for the CHP5 Plant. CFB boiler technology has been widely adopted in power plants because it saves coal, it is highly efficiency and highly reliability. An outstanding advantage of a CFB boiler is its ability to use limestone during combustion to desulphurize the coal combustion products. Generally, the combustion temperature of a CFB boiler is between 800 °C and 900 °C and it is the temperature section at which the activity of limestone decomposing into lime is great and the desulphurization efficiency is high. Therefore, with appropriate Ca/S and particle size of limestone, a desulphurization efficiency of 80% is able to be reached when Ca/S is about 2.0, thus a CFB boiler is comparatively fit for middle and low sulfur fuel.

551. Limestone powder is employed as the desulfurization absorbent. The quality requirements of limestone are: CaO>50％；MgO≤2％，SiO2≤2%, fineness is: 250 mesh, sieving residue<10%. The annual Limestone consumption is 173,000 tons.

3. Denitration Equipment

552. Selective Non-catalytic Reduction (SNCR) system. In SNCR systems, a reagent is injected into the flue gas in the furnace within an appropriate temperature window. Emissions of NOx can be reduced by 30% to 50%. The NOx and reagent (urea was proposed) to react to form nitrogen and water. A typical SNCR system consists of reagent storage, multi-level reagent-injection equipment, and associated control instrumentation. The SNCR reagent storage and handling systems are similar to those for SCR systems. However, because of higher stoichiometric ratios, both the ammonia and urea SNCR processes require three or four times as much reagent as SCR systems to achieve similar NOx reductions.

553. The temperature window for efficient SNCR operation typically occurs between 900 °C and 1,100 °C depending on the reagent and condition of SNCR operation. When the reaction


Appendix 3-121

temperature increases over 1000 °C, the NOx removal rate decreases due to thermal decomposition of ammonia. On the other hand, the NOx reduction rate decreases below 1000 °C and urea slip may increase. The optimum temperature window generally occurs somewhere in the steam generator and convective heat transfer areas. The longer the reagent is in the optimum temperature window, the better the NOx reduction. Residence times in excess of 1 second yield optimum NOx reductions. However, a minimum residence time of 0.3 seconds was proposed to achieve moderate SNCR effectiveness.

554. Urea slip from SNCR systems occurs either from injection at temperatures too low for effective reaction with NOx or from over-injection of reagent leading to uneven distribution. Controlling ammonia slip in SNCR systems is difficult since there is no opportunity for effective feedback to control reagent injection. The reagent injection system must be able to place the reagent where it is most effective within the boiler because NOx distribution varies within the cross section. An injection system that has too few injection control points or injects a uniform amount of ammonia across the entire section of the boiler will almost certainly lead to a poor distribution ratio and high ammonia slip. Distribution of the reagent can be especially difficult in larger coal-fired boilers because of the long injection distance required to cover the relatively large cross-section of the boiler. Multiple layers of reagent injection as well as individual injection zones in cross-section of each injection level are commonly used to follow the temperature changes caused by boiler load changes.

4. Ash Comprehensive Utilization

555. Fly ash generated during power generation in the coal-fired power plant is one of the solid waste sources. It is removed from the plant exhaust gases primarily by the ESP. Physically, fly ash is a very fine, powdery material, composed mostly of silica nearly all particles are spherical in shape. Fly ash is a pozzolan, a siliceous material that in the presence of water will react with calcium hydroxide at ordinary temperatures to produce cementitious compounds. Because of its spherical shape and pozzolanic properties, fly ash is useful in cement and concrete applications, such as minus waterborne, workability, increasing penetration-proof quality, reducing creep and long-term high strength after mixing coal ash. It has been widely applied in building materials. Using coal ash can make a rather considerable economic effect. The spherical shape and particle size distribution of fly ash also make it a good mineral filler in hot mix asphalt applications and improve the fluidity of flowable fill and grout when it is used for those applications. The dry ash application research has been successful in recent years. Fly ash applications include its use as a:

Raw material in concrete products and grout

Feed stock in the production of cement

Fill material for structural applications and embankments

Ingredient in waste stabilization and/or solidification

Ingredient in soil modification and/or stabilization

Component of flowable fill

Component in road bases, sub-bases, and pavement

Mineral filler in asphalt

556. Bottom ash is agglomerated ash particles, formed in CFB furnaces, which are too large to be carried in the flue gases and impinge on the furnace walls or fall through open grates to an ash hopper at the bottom of the furnace. Physically, bottom ash is typically grey to black in color, is quite angular, and has a porous surface structure. Bottom ash is coarse, with grain sizes spanning from fine sand to fine gravel.

557. Bottom ash can be used as a replacement for aggregate and is usually sufficiently well-graded in size to avoid the need for blending with other fine aggregates to meet gradation


Appendix 3-122

requirements. The porous surface structure of bottom ash particles make this material less durable than conventional aggregates and better suited for use in base course and shoulder mixtures or in cold mix applications, as opposed to wearing surface mixtures. This porous surface structure also makes this material lighter than conventional aggregate and useful in lightweight concrete applications. More advantageously, the bottom ash from CFB of the CHP5 will be more desirable for cements and the like construction materials, because it contains gypsum that is a beneficial additive to improve the function of cements and the like.

558. Bottom ash applications include its use as a:

Filler material for structural applications and embankments

Aggregate in road bases, sub-bases, and pavement

Feed stock in the production of cement

Aggregate in lightweight concrete products

Snow and ice traction control material

559. CHP5 is scheduled to be located in the urban area of UB city, which provides a good opportunity for comprehensive ash utilization. At the meeting with related construction materials agencies and manufacturers in UB, the TA Team was informed that the ash generated from the power plant is desirable for construction materials sector. The consultants have learned that construction sector and building material sector have the desire to utilize ash generated from the power plant. Actually a small quantity of ash has been utilized already in UB. However, the existing CHP plants in UB use the wet method to handle ash which makes it difficult to use by the construction sector. Due to local unavailability of ash most of which is handled through wet process, some of the local manufacturers have to import ash from adjacent countries for producing construction materials.

560. We’ve recommended the dry method for handling ash from the CHP5 to make it easy for other sectors to utilize ash as raw materials for road and building constructions. The project design uses an ash dividing and dry ash, dry emissions system, that provides the best possibilities for comprehensive ash utilization in the future. The application prospects are vast. However, uncertainty over the radiation level of the ash might limit the utilization of ash to certain extent. In order to assess whether the ash can be beneficially used as raw materials for the construction sector, the consultants engaged the Radiation Lab of the University of Science and Technology. More than 38 coal ash and slag samples were tested and the test results along with the radiation standards are summarized in the following table. The Mongolian national radioactivity standards are for radium equivalent (Bq/kg): <370 for living house and public service building; < 740 for industrial building and road construction.

Table 6.24: Radioactivity of Coal, Ash and Other Construction Materials

No. Sample ID Isotope Activity (Bq/kg) Radium Equivalent

(Bq/kg) 226Ra 232Th 40K

1 Baganuur coal 27 3 < 29.4 28.3

2 Shivee-Ovoo coal 19 6 23.8

3 CHP3 ash and slag avg 135 38 526 228

4 CHP4 Baganuur ash 168 61 268 268

5 CHP4 Shivee-Ovoo ash 267 142 268 468

6 CHP4 Baganuur slag 145 39 229 214

7 CHP4 Shivee-Ovoo slag 236 104 326 394

8 Sand 23.3 20.5 1124 146


Appendix 3-123

9 Gravel 21.7 17.0 1015 131

10 Limestone 23.2 5.7 422.9 67

Source: National University of Mongolian and TA Team estimate.

561. An average value as 228 Bq/kg of radium equivalent for natural radioactive isotopes in ash and slag sample from boiler in TPP-3 and TPP-4 where Baganuur coal dominantly burning is 38% lower than the permissible limits (370 Bq/kg) in purpose of that utilization of building material for public and plant building. Furthermore, we reached up an initial conclusion that there is a possibility to use as a building material mixing with waste ash and other low radioactive components.

562. An average value as 468 Bq/kg of radium equivalent for natural radioactive isotopes in ash sample from boiler, where Shivee-Ovoo coal burning, in TPP-4 is 27% higher than the permissible limits in purpose of that utilization of building material for public and plant building. Hence ash of Shivee-Ovoo coal mine, instant of its utilization of plant building, is possible to use as mixing with other raw material for which reducing radiation as low as reasonably achieve, to public and plant building.

563. However, average value as 394 Bq/kg of radium equivalent for natural radioactive isotopes in slag sample of Shivee-Ovoo is 7 % higher than the permissible limits in purpose of that utilization of building material for public and plant building. Hence, instant of its utilization in plant building, slag of Shivee-Ovoo coal is possible to use as mixing with other raw material, reducing radiation as low as reasonably achieve, to public and plant building.

564. In order to ensure the ash can be used for building material, BMMA performed laboratory test on the building material made of ash and other raw material. The results are shown in the following Table 7.7.

Table 6.25: Combined Laboratory Results of Building Material and Ash Additive

Name of material, composition /kg/, other characteristics, 1m3

Ready mix concrete M250

Gravel /5-20/ Sand Cement Ash Water Volumetric

weight, kg/m3

Hardness characteristic,

kg/cm2

Share of ash in total dry weight

Radium equivalent,

Bq/kg

1290 378 330 180 190 2345 115 8.3 128.2

foam concrete

foam Cement Ash Water Volumetric

weight, kg/m3


kg/cm2


Radium equivalent,

Bq/kg

1 340 250 250 900 7.5 42 140.8

Slag concrete

Slag Sand Cement

Water Volumetric

weight, kg/m3


kg/cm2


Radium equivalent,

Bq/kg

460 391 326 220 1760 66.5 39 137

Expanded aleurolite concrete

Gravel /5-20/,

aleurolite Cement Ash Water

Volumetric weight, kg/m3


kg/cm2


Radium equivalent,

Bq/kg

830 220 200 160 1150 14.3 16 160.9

Polystirol concrete


Appendix 3-124

Polystirol, L Cement Ash Water Volumetric

weight, kg/m3


kg/cm2

Share of ash in total dry

weight

Radium equivalent,

Bq/kg

1100 250 250 175 600 5 49 166

Expanded ceramsite concrete

Gravel /5-20/, of ceramsite

Cement Ash Water Volumetric

weight, kg/m3


kg/cm2


weight

Radium equivalent,

Bq/kg

620 220 200 190 970 33.3 19.2 163.3

Composite structural concrete /polystirol, aleurolite, ash/

Polystirol, L Aleurolite Cement Ash Water Glue Volumetric weight, kg/m3


kg/cm2


weight

Radium equivalent,

Bq/kg

500 300 300 154 170 0.6 900 7 20.3 124

Composite structural concrete /pårlitå, ceramsite , ash/

Perlite Ceramsite Cement Ash Water Volumetric

weight, kg/m3


kg/cm2


weight

Radium equivalent,

Bq/kg

45 152 180 575 280 1220 28.5 60.4 219

Composite structural concrete /wood sawdust , ceramsite , ash/

Wood sawdust Ceramsite Cement Ash Water



kg/cm2


weight

Radium equivalent,

Bq/kg

100 345 300 250 240 1200 5 25.1 144

Perlite concrete

Perlite Sand /0-5/ Cement Ash Water



kg/cm2


weight

Radium equivalent,

Bq/kg

140 213 284 216 284 950 7.5 25.3 142

Magnum concrete

Magnum oxide MgO MgCl2

Slag /0-5/ Ash Water wood

sawdust


Hardness characteristic

, kg/см2


weight

Radium equivalent,

Bq/kg

100 40 300 220 100 60 970 58.6 72.2 185

Source: BMMA and Nuclear Physics Department, NUM

565. Based on the above results, it’s concluded that the ash from the Baganuur coal mines can be used as construction materials for any purposes without restrictions. The ash from Shivee-Ovoo coal mine can be mixed with other construction materials and then used as construction material.

R. Heating Network

1. Introduction

566. From a hydraulic balance and the least cost perspectives, the heat source should be constructed close enough to the center of the heating areas. However, considering the environmental, social, land, resettlement, and power transmission factors, coal-fired CHPs are only constructed close to the city edge or suburban areas. In some cases, CHPs might be constructed 15 to 20 km away from the urban center. Although relatively longer heating pipelines are to be installed, these type of CHP designs are still justified, thanks to outstanding advantages such as higher energy efficiency, better environmental performance,


Appendix 3-125

and lower operational cost.

567. In accordance with the urban development plan, the urban area will develop in an east-west direction. Once the CHP5 is put into service, the CHP4 and CHP5 will be the two major heat sources for the UB district heating system. The CHP5 is proposed to further extend the district heating services to the urban area of UB and to enhance power supply capacity of the CES. More specifically, the CHP5 is proposed to be the heat source for customers in east UB because CHP4, the largest heat source, is located in the western suburban area of UB. Due to protection of the drinking water reservoir and unreliable geological conditions, Uliastai is not recommended for the future CHP5 site. The CHP3 site is highly recommended for the CHP5 site because its existing facilities could be fully utilized in addition to its limited social and land issues. However, the hydraulic performance of its primary system remains a major concern.

568. To ensure a balanced heat transmission and distribution, the TA team conducted a detailed hydraulic calculation on the index primary circuit to describe the feasibility and reliability of the hydraulic system of CHP5.

2. Proposed Pipeline System and Operation Parameters

a. Proposed Pipeline System

569. Pre-insulated bonded pipe is by far the most commonly used technology for both new district heating and cooling systems as well as for rehabilitation of existing systems. Steel pipes, insulation materials made of polyurethane foam (PUR), and high density polyethylene (HDPE) are bonded into one piece in a sandwich-like structure. Compared to on-site insulation pipe buried in a tunnel, a direct-buried pre-insulation bonded pipe has many advantages, such as lower capital cost; reduced heat losses; improved energy efficiency; better anti-corrosive and insulation performance; longer service life; limited land acquisition requirement; and shorter installation cycles, which are conducive to environmental protection and offer great conditions for construction of municipal facilities.

570. The pre-insulation bonded pipe is designed to apply a direct-buried method. However, some pipelines may adopt overhead and/or trench laying modes, depending on the local site conditions.

b. Working Parameters

571. Working Temperatures. Upon completion of the CHP5, about 820 MW of power generation capacity and 1,281 MW (1101Gcal/hr) of heating capacity are expected. The CHP5, in combination with the CHP4, is expected to meet the district heating demand of the urban area of UB. The large amount of heating capacity of the CHP5 would generate a higher temperature difference of feed and return waters, allowing for a reduced pipeline diameter. Currently, the feed and return water temperatures in the high temperature heating system can reach 150 °C and 70 °C, with an 80 °C temperature difference. However, this high temperature system is no longer used, because pre-insulation bonded pipe is not designed for use at over 135°C.

572. According to the European Standard EN253 “Pre-insulation Bonded Pipe System for Underground Hot Water Networks - Pipe Assembly of Steel Pipes, Polyurethane Thermal Insulation and Outer Casing of Polyethylene,” the service life of the pre-insulation bonded pipe is expected to last for a minimum of 30 years, provided that it operates continuously at a temperature of 120 °C. If it operates continuously at a temperature of 115 °C, the service life is expected to last much longer (at minimum, 50 years). However, if the working temperature remains at over 135 °C on a continuous basis, the service life is expected to last a dramatically shorter time (10 years or less). Therefore, it is recommended that the system does not operate continuously at the output temperatures of 135 °C. In addition, the existing district heating system in UB area is operating at temperatures of 135 °C on the feed water side and of 70 °C on the return water side. Therefore, it is recommended that the 135 °C feed


Appendix 3-126

water temperature and 70 °C return water temperature be defined for the heating system of CHP5.

573. Heating Capacity and Flow Rate. Estimated heat capacity of the CHP5 is 1,101 GCal/hr. With the addition of heating capacity from the high-pressure (HP) part of CHP3, the total heating capacity from the new CHP5 will be 1,476 Gcal/h. 485 Gcal/h can be transmitted by the existing high-pressure circuit and low-pressure circuit with DN800 of diameter. In addition, the CHP4 is interconnected with CHP3 by DN1000 circuit at point 703, from which point the network will be disconnected with the CHP4 and connected with the CHP5, with 293 Gcal/h of heating capacity. The other DN800 pipeline should be disconnected with CHP4 at point 1,136 and connected with CHP5, which has 263 Gcal/h of heating capacity. In total, these existing four circuits will have 1,041 Gcal/h. Consequently, only 435 Gcal/h of heating capacity should be transmitted by the new pipeline from CHP5 to the east area. The heating networks for the existing customers have been available, and can meet the demand of the existing customers. We will not conduct detailed hydraulic calculation. The major concern is to provide reliable and comfortable heating service to new customers in the east area, which will have 506 MWt (435 Gcal/hr) of heating capacity. Because expected customer demand in the east area is/will be concentrated in the remote edge of the city, such as the Uliastai Valley, the detailed hydraulic calculation should be conducted there to clarify the feasibility of heating service. The 506 MWt (435 Gcal/hr) heating capacity is scheduled to be accommodated by the new heating pipeline. Therefore, the size of the new heating pipeline is to be designed to accommodate a heating capacity of 506 MW (435 Gcal/hr). Based on the above heating capacity and temperature estimation, the flow rate of each pipe segment can be calculated according to the following formula8:

G = 3.6 [ Q/C (tf-tr)] × 10³, ton/hr Wherein: G - design flow rate of feed and return waters, ton/hr

Q - design heat load, MW C - specific heat, kJ/(kg°C), (=4.186) tf, tr - design feed and return water temperatures, °C (=135/70)

From the formula, the flow rate of the main pipeline of the CHP5 is calculated at 6,690 ton/hr.

574. Working Pressure. Nominal pressure and key operating parameters of the heating system shall be defined based on the existing system condition, hydraulic calculations, and cost analysis. In line with international design specification, a nominal pressure of 1.6 MPa is defined for the primary circuit of the district heating system. When the nominal pressure is greater than 1.6 MPa, the overall capital cost associated with equipment, pipelines, and fittings would rise. On the contrary, the heating capacity would be greatly limited. The primary circuit of the existing district heating system in UB is working under a nominal pressure of 1.6 MPa. To best fit the existing heating system, the nominal pressure of the primary circuit to be connected with the CHP5 should be defined at 1.6 MPa.

c. Proposed Route of Primary Heating Pipeline

575. CHP3 is located in the southwest edge of the urban area of UB. CHP3 is hooked up to three primary circuits with diameters of DN1000 and DN800, respectively. One DN800 primary circuit connects the high-pressure system heading northward with the customers in the central area of UB. Another DN800 circuit connects the low-pressure system with the customers in the southeast area of UB. In addition, one DN1000 circuit is connected with CHP4 for backup.

576. To reduce the capital cost and to minimize potential social and environmental impacts likely brought about by the project, the TA team recommends that the existing pipeline system of the CHP3 be fully utilized for CHP5 after these aged, deteriorated, and unreliable pipelines are upgraded. On top of that, an additional new primary circuit is to be installed to form the 8 Source: Practical District Heating Handbook. Shanhua Li. March, 2006.


Appendix 3-127

entire pipeline system for CHP5. The following principals are suggested to comply with in designing the pipeline system for CHP5:

Pipelines to be installed in an area with high heating demand and to avoid passing through areas without heating demand;

Pipelines are to avoid passing through main traffic roads and commercial streets so as to minimize potential impacts likely brought about during construction, operation, and maintenance;

Pipelines are to be installed beneath sidewalks;

To apply branch networks or partial ring networks; and

To introduce a phased approach for construction of the main pipeline.

577. Conceptually, CHP5 is designed to provide heating service to customers in the east area of UB. The TA team conducted a preliminary survey and identified a new pipeline route suitable for CHP5. Under the CHP3 site option, the new route starts at the industrial district area, via the 5A Primary Pipeline, the Energy Authority building, the Dundgol River Dam, and the Peace Bridge, then returns back to Sun Road and finally ends at the Narantuul Market, being hooked up to the existing pipelines. The heating circuit is to be divided into two branch networks at the Narantuul Market: one is to be connected with customers in the Amgalan area and another is to connect customers residing in the Altan-Ulgii area and areas further east area of UB. The index circuit is designed at 16.7 km in length. The detailed route of the pipeline and locations of main substations are shown in Figure 6.1.

3. Hydraulic Calculation and Pressure Curve

Hydraulic Calculation 578. Hydraulic resistance of a pipeline system normally consists of friction resistance and local resistance. The friction resistance can be calculated in accordance with the following formula9:

∆Pf =∑λ·(Li/D) · (ρ· v 2)/2 Wherein: ∆Pf - friction resistance, Pa; λ - friction coefficient, λ=0.11, Kd/De0.25, Kd=0.5 for hot water pipe, De= internal diameter; Li - Friction length of a single pipeline segment, m; D - internal pipeline diameter, m; ρ - water density, kg/m3; 930 kg/m3 for feed water and 977.98 kg/m3 for return water v - water flow rate, m/s.

579. The total hydraulic resistance of main pipeline can be calculated in the following formula: ∆PT = (1+α) R·L Wherein: ∆PT - total friction resistance loss, Pa;

R - specific resistance, R=∆Pf / L, 30～70 Pa/m; L - Friction length, m; α - local resistance percentage of total friction resistance

580. In accordance with the urban development plan, the main substations for new expected customers are tentatively located as shown in Figure 6.12, and their capacity is designed as shown in the Table 6.25.

9 Source: Practical District Heating Handbook. Shanhua Li. March, 2006.


Appendix 3-128

Table 6.25: Main Substations List

Start Finish Consumer Q, Gcal/hr G, ton/hr Ha, mwc

2 33 Chinges Avenue 31.130 478.923 69.0

28 32 Olimpic Town 15.000 230.769 47.9

29 31 Weave factory around 13.300 204.615 36.6

29 30 Marshal Town 16.460 253.231 33.5

4 27 East Selbe 33.750 519.231 51.9

22 26 XIV SD-1 30.000 461.538 22.2

23 25 XIV SD-2 30.000 461.538 19.6

23 24 XIV SD-3 30.000 461.538 12.8

15 21 Amgalan-1 30.000 461.538 65.0

16 20 Amgalan-2 30.000 461.538 67.0

17 19 Amgalan-3 30.000 461.538 34.3

17 18 Amgalan-4 30.000 461.538 30.9

8 14 Alman-Ulgii-1 25.000 384.615 66.2

9 13 Altan-Ulgii-2 25.000 384.615 64.9

10 12 Altan-Ulgii-3 17.500 269.231 65.0

10 11 Mamba Temple 15.750 242.308 68.8

35 36 Uliastai-1 16.000 246.154 49.2

35 37 Uliastai-2 16.000 246.154 49.2

Total: 434.9 6690.6 -

Source: TA Team

Wherein:

Start - starting point of the calculation section

Finish - finisting point of the calculation section

Consumer - name of heat consumer

Q - heat load, Gcal/hr

G - flowrate, ton/hr

Ha - available head, m.w.c


Appendix 3-129

Figure 6.12: Route of the Main Heating Network and Location of the Main Substations

Source: TA Team


Appendix 3-130

581. In accordance with the international experience, the DN1000 diameter of the maximum main pipeline is reasonable for 506 MW (435 Gcal/hr) of heating capacity. However, considering the potential of adjusting urban development and increasing the heating capacity, DN1200 diameter of the maximum main pipeline will be more desirable for matching the expansion of the heating system. Therefore, the hydraulic calculation was conducted in terms of two options. Option 1: maximum diameter the network is designed as DN1200; and Option 2: maximum diameter the network is designed as DN1000.

Option 1 582. In this option, the hydraulic resistance will be lower than the normal level, and consequently the required water head for driving the circulation of the hot water in the networks will be lower than normal. One boosting pump station is required to ensure the reliable heating supply to further east customers. The detailed results and parameters are shown in Table 6.26.

Table 6.25: Hydraulic Calculation of New Pipeline of CHP-5 (135/70°C) Start Finish Level D L G ω λ R Hf Hl Hs He Ha1 Ha2

1 2 1282 1200 3500 6690.6 1.687 0.0188 2.212 7.74 0.77 17.04 17.0 73.0 73.0

2 3 1286 1200 2600 6211.7 1.566 0.0188 1.907 4.96 0.50 10.91 27.9 62.1 62.1

3 4 1286 1000 740 5523.1 2.005 0.0196 3.920 2.90 0.29 6.38 34.3 55.7 55.7

4 5 1289 1000 2400 5003.8 1.817 0.0196 3.217 7.72 0.77 16.99 51.3 38.7 38.7

5 6 1296 1000 1500 3619.2 1.314 0.0196 1.683 2.52 0.25 5.55 56.8 33.2 83.2

6 7 1332 800 2200 1773.1 1.006 0.0207 1.303 2.87 0.29 6.30 63.1 26.9 76.9

7 8 1332 600 350 1280.8 1.292 0.0223 3.082 1.08 0.11 2.37 65.5 24.5 74.5

8 9 1331 600 750 896.2 0.904 0.0223 1.509 1.13 0.11 2.49 68.0 22.0 72.0

9 10 1329 500 850 511.5 0.743 0.0234 1.283 1.09 0.11 2.40 70.4 19.6 69.6

10 11 1338 500 1250 242.3 0.352 0.0234 0.288 0.36 0.04 0.79 71.2 18.8 68.8

10 12 1331 300 400 269.2 1.086 0.0269 5.261 2.10 0.21 4.63 75.0 15.0 65.0

9 13 1336 300 300 384.6 1.552 0.0269 10.738 3.22 0.32 7.09 75.1 14.9 64.9

8 14 1336 300 350 384.6 1.552 0.0269 10.738 3.76 0.38 8.27 73.8 16.2 66.2

6 15 1300 800 400 1846.2 1.047 0.0207 1.412 0.56 0.06 1.24 58.0 32.0 82.0

15 16 1306 800 820 1384.6 0.786 0.0207 0.794 0.65 0.07 1.43 59.4 30.6 80.6

16 17 1313 500 600 923.1 1.341 0.0234 4.179 2.51 0.25 5.52 64.9 25.1 75.1

17 18 1321 300 1300 461.5 1.862 0.0269 15.46220.10 2.01 44.22 109.1-19.1 30.9

17 19 1311 300 1200 461.5 1.862 0.0269 15.46218.55 1.86 40.82 105.7-15.7 34.3

16 20 1305 300 400 461.5 1.862 0.0269 15.462 6.18 0.62 13.61 73.0 17.0 67.0

15 21 1299 300 500 461.5 1.862 0.0269 15.462 7.73 0.77 17.01 75.0 15.0 65.0

5 22 1289 800 500 1384.6 0.786 0.0207 0.794 0.40 0.04 0.87 52.2 37.8 37.8

22 23 1290 500 500 923.1 1.341 0.0234 4.179 2.09 0.21 4.60 56.8 33.2 33.2

23 24 1293 300 600 461.5 1.862 0.0269 15.462 9.28 0.93 20.41 77.2 12.8 12.8

23 25 1290 300 400 461.5 1.862 0.0269 15.462 6.18 0.62 13.61 70.4 19.6 19.6


Appendix 3-131

Start Finish Level D L G ω λ R Hf Hl Hs He Ha1 Ha2

22 26 1292 300 400 461.5 1.862 0.0269 15.462 6.18 0.62 13.61 65.8 24.2 24.2

4 27 1286 400 400 519.2 1.178 0.0248 4.285 1.71 0.17 3.77 38.1 51.9 51.9

3 28 1284 400 320 688.6 1.563 0.0248 7.537 2.41 0.24 5.31 33.2 56.8 56.8

28 29 1287 400 1200 457.8 1.039 0.0248 3.332 4.00 0.40 8.80 42.0 48.0 48.0

29 30 1285 250 540 253.2 1.471 0.0284 12.209 6.59 0.66 14.50 56.5 33.5 33.5

29 31 1283 250 650 204.6 1.189 0.0284 7.971 5.18 0.52 11.40 53.4 36.6 36.6

28 32 1286 250 400 230.8 1.341 0.0284 10.139 4.06 0.41 8.92 42.1 47.9 47.9

2 33 1281 400 500 478.9 1.087 0.0248 3.646 1.82 0.18 4.01 21.0 69.0 69.0

7 34 1354 500 2600 492.3 0.715 0.0234 1.189 3.09 0.31 6.80 69.9 20.1 70.1

34 35 1348 400 1900 492.3 1.117 0.0248 3.852 7.32 0.73 16.10 86.0 4.0 54.0

35 36 1352 300 500 246.2 0.993 0.0269 4.398 2.20 0.22 4.84 90.8 -0.8 49.2

35 37 1344 300 500 246.2 0.993 0.0269 4.398 2.20 0.22 4.84 90.8 -0.8 49.2

Source: TA Team

Note: Networks before boosting pump station Section with boosting pump station (Hpump=50 m; G=3700-4000 ton/hr) Networks after pump station

Wherein: Start - starting point of the calculation part Finish - finisting point of the calculation part Level - elevation, m D - pipe dimention, mm L - pipe lenght, m G - flowrate, ton/hr ω - water speed, m/s λ - friction factor R - pressure drop for 1 meter length of pipeline, mm.w.c/m Hf - pressure drop caused by friction, m.w.c Hl - pressure drop caused by local resistance, m.w.c Hs - summary pressure drop of supply and returtn lines, m.w.c He - pressure drop from CHP at the end of present section, m.w.c Ha1 - available head without pump substation, m.w.c Ha2 - available head with pump substation, m.w.c

583. In accordance with the hydraulic calculation and local topography, a booster pump station (Water Head: 50 m; Flow Rate: 3,700 ton/hr) in the feeding pipeline will be designed to be positioned between Point 5 and Point 6, where it is closest to the XIV residential area. Based on the hydraulic calculation, the hydraulic pressure curve along the networks was prepared as shown in the Figure 6. 13. From the Figure 6. 13, it can be found that the available water head for the subsequent substation in Uliastai will be 30 m water column; in Amgalan, a 49 m water column; and in Altan-Ulgii, a 45 m water column. Normally, required water head for substation ranges from 10 to 15 m water column. Therefore, the further east customers can safely and reliably get the heating service from CHP5. This hydraulic calculation justifies that it is hydraulically feasible to supply heating service from CHP5 to the easternmost customers.


Appendix 3-132

Figure 6.13: Hydraulic Pressure Curve Along the Network

Source: TA Team

Option 2 584. In this option, the hydraulic resistance will be similar to the normal level, and consequently the required water head for driving the circulation of the hot water in the networks will be similar to the normal level. Two boosting pump stations will be required to ensure the reliable heating supply for the easternmost customers. The detailed results and parameters are shown in Table 6.27.

66


Appendix 3-133

Table 6.27: Hydraulic Calculation of New Pipeline of CHP-5 (135/70°C)

No. Section Flow Rate ton/hr

DN mm

Length m

Equivalent Length

m

Total Length

m Velocity

m/s Unit Resistance

mm Total

Resistance mm

Feed m

Return m

Ha m

1 1-2 6682.9 1020×12 3500 700 4200 2.4 4.99 20969.4 99.0 41.0 58.1

2 2-Boosting Pump 6204 1020×12 2500 1000 3500 2.2 4.3 15059.7 84.0 56.0 27.9

4 Boosting Pump 6204 1020tin 145.0 56.0 89.0

Boosting Pump-3 6204 1020tin 100 40 140 2.2 4.3 602.4 144.4 56.6 87.8

6 3-4 5515.4 1020×12 740 296 1036 2 3.4 3523 140.9 60.1 80.7 7 4-5 5003.8 920×10 2400 960 3360 2.2 4.77 16011.8 124.9 76.1 48.7

8 5-Boosting Pump 3619.2 820×9 1100 400 1500 2 4.57 5966.9 118.9 82.1 36.8

Boosting Pump 3619.2 8209. 166.5 84.9 81.6

11 Boosting Pump-6 3619.2 8209. 400 200 600 2 4.57 852.4 165.6 85.8 79.8

12 6-7 1773.1 630×9 2200 880 3080 1.7 4.45 13721 151.9 99.5 52.4 13 7-8 492.31 426×8 4500 1350 5850 1 2.86 16740.9 135.2 116.3 18.9 14 8-1# 246.15 325×7 500 150 650 0.9 3.05 1984.3 133.2 118.2 15.0 17940 5976 23916 98202 8-2# 246.15 325×7 500 150 650 0.9 3.05 1984.3 133.2 118.2 15.0

16 7-9 1280.8 529×8 350 140 490 1.7 5.97 2926.1 149.0 102.4 46.6 17 9-10 896.15 478×8 750 300 1050 1.5 5.07 5319.2 143.7 107.8 35.9 18 10-11 511.54 426×8 850 255 1105 1.1 3.09 3414 140.3 111.2 29.1 19 11-3# 242.31 325×7 1250 375 1625 0.9 2.96 4806.9 135.5 116.0 19.5 11-4# 269.23 273×7 400 120 520 1.4 9.54 4962.4 135.3 116.1 19.2

21 10-5# 384.62 273×7 300 90 390 2 19.48 7595.5 136.1 115.4 20.7 22 9-6# 384.62 273×7 350 105 455 2 19.48 8861.5 140.1 111.3 28.8 3200

23 6-12 1846.2 529×8 400 160 560 2.5 12.41 6948.2 158.7 92.7 66.0 24 12-13 1384.6 529×8 820 328 1148 1.9 6.98 8012.2 150.7 100.8 49.9 13-14 923.08 426×8 600 180 780 1.9 10.06 7847.3 142.8 108.6 34.2


Appendix 3-134

No. Section Flow Rate ton/hr

DN mm

Length m

Equivalent Length

m

Total Length

m Velocity

m/s Unit Resistance

mm Total

Resistance mm

Feed m

Return m

Ha m

26 14-7# 461.54 377×7 1300 390 1690 1.2 4.77 8054.9 134.8 116.7 18.1 27 14-8# 461.54 377×7 1200 360 1560 1.2 4.77 7435.3 135.4 116.0 19.4 28 13-9# 461.54 273×7 400 120 520 2.4 28.05 14583.5 136.1 115.3 20.8 29 12-10# 461.54 273×7 500 150 650 2.4 28.05 18229.3 140.5 111.0 29.5 3120 30862.5 5-15 1384.6 478×8 500 200 700 2.3 12.09 8465.5 116.4 84.6 31.8

31 15-16 923.08 426×8 500 150 650 1.9 10.06 6539.4 109.9 91.1 18.7 32 16-11# 461.54 377×7 600 180 780 1.3 5.05 3940.3 105.9 91.1 14.8 33 17-12# 461.54 325×7 400 120 520 1.7 10.73 5580.7 104.3 96.7 7.6 34 18-13# 461.54 325×7 400 120 520 1.7 10.73 5580.7 110.8 90.2 20.6 4-14# 511.54 377×7 400 120 520 2.7 34.45 17914.4 123.0 78.0 44.9

36 3-17 688.62 377×7 320 96 416 1.8 10.61 4413.7 140.0 61.0 79.0 37 17-18 457.85 325×7 1200 360 1560 1.7 10.56 16475.4 123.5 77.5 46.0 38 19-15# 253.23 219×6 540 162 702 2.1 27.38 19221.7 104.3 96.7 7.6 39 18-16# 204.62 219×6 650 195 845 1.7 17.88 15106.2 108.4 92.6 15.8 17-17# 230.77 219×6 400 120 520 1.9 22.74 11824.4 128.2 72.8 55.3

41 2-18# 478.92 273×7 500 150 650 2.5 30.2 19628.5 79.4 60.6 18.8



Appendix 3-135

585. In accordance with the hydraulic calculation and local topography, one booster pump station (Water Head: 60 m; Flow Rate: 6204 ton/hr) in the feeding pipeline will be designed to be positioned between Point 2 and Point 3. Another booster pump station (water head: 52 m, flow rate: 3600 ton/hr) will be designed to be positioned between Point 5 and Point 6. Based on the hydraulic calculation, the hydraulic pressure curve along the networks was prepared as shown in Figure 6.14. Figure 6.14 indicates it can be found that the available water head for the most distant substation in Uliastai will be a 15 m water column. This hydraulic calculations justify that it is hydraulically feasible to supply heating service from CHP5 to the easternmost customers.

Figure 6.14: Hydraulic Pressure Curve Along the Network

Source: TA Team

586. However, the DN1000 main pipeline will limit the expansion for the district heating system and will increase the power consumption of circulating pumps compared to a DN1200 main pipeline system. In addition, the maximum water head will reach 165 m water column, which will possibly cause over pressure in some direct connection loop. This option is not recommended. We recommend Option 1 to use a DN1200 main pipeline and one booster pump station. This option can meet the more rapid increase of heat demand than expected, reduce the power consumption of the circulating pumps, and mitigate the risk of overpressure.

4. Hydraulic Balance

587. Hydraulic balance is one of the major concerns in designing a district heating system to accommodate huge amounts of heating capacities. Under the Uliastai site option, similar measures are necessary to be taken to ensure a well-maintained hydraulic balance. Under the CHP3 site option, a well-maintained hydraulic balance could be achieved through accurate hydraulic balance calculation, installation of functioning hydraulic balance valves, effective control and monitoring system, and effective operation and maintenance implementation.

588. Hydraulic balance includes two parts: initial or static balance and dynamic balance. The initial or static balance means that the heating system reaches a stable hydraulic balance under designed working conditions. The static balance is maintained through proper pipeline system design and systematic adjustment manually (initial state) or automatically. The static balance is relatively easily maintained compared to the dynamic balance.


Appendix 3-136

589. Dynamic balance relates to the control and regulation of the heating system, which is very important for conserving energy, maintaining a stable and reliable heating system, and ensuring a quality heating service. Variable flow rate control technology has been widely applied in the primary heating system, in which the hydraulic balance varies with flow rate changes. It is nearly impossible to maintain a sound dynamic balance without an automatic control and regulation system being implemented. As the technology develops in hydraulic balance valve and control and monitoring system, the hydraulic system is regulated to continuously accommodate the heat demand variations with outdoor temperature, so as to maintain a dynamic balance. Nowadays, the modern district heating system with effective control system could maintain a sound hydraulic balance, as shown in Figure 6.15.

Figure 6.15: Hydraulic System Diagram with Hydraulic Balance Valve

Source: TA Team

5. Conclusion

590. Based on the above analysis, it is concluded that the hydraulic circulation can be established through a proper engineering design of the pumping and pipeline systems and that the hydraulic balance can be maintained through the installation of effective balance valves and a control and monitoring system to ensure a stable and reliable heating system.

S. Institutional and Human Resources Arrangements

591. Principles for power plant institutional and human resources arrangements are as follows:

To meet Class A modern thermal power plant objective, a new standardized staffing supervision procedure is to be implemented for efficient production and management;

To establish an efficient and well-structured organization with clear definition of departmental and post responsibilities;

To implement an equipment overhaul system. Currently the power plant doesn’t have staff designated responsible for overhaul and minor repairs. Instead, the overhaul and repairs are outsourced to relevant overhaul companies. The maintenance staff of the power plant is mainly responsible for temporary repairs, accidental maintenance and routine maintenance management. The overhaul spare parts are contracted or delegated to relevant overhaul companies for procurement and/or processing. The repair plan is prepared by production and technical departments, including routine equipment inspection and defects identification; while

Δp

feed

Return

user


Appendix 3-137

the overhaul technology is proposed by the overhaul department, and a liaison person is assigned for quality and progress control.

592. The thermal power plant shall be designed with appropriate staff numbers. The staff numbers of the entire plant is recommended to be 648, including preparation staff, see Table 6.28 below:

Table 6.28: Proposed Staffing Plan

Items Quantity of Staff Notes

I. Production personnel 558

1) Unit operation 210

1. Main Equipment Operation 150

2. Auxiliary System Operation 60

2) Laboratory center 24 Including test, labor safety, and environmental protection

3) Unit maintenance 210

1. Main Equipment 120

2. Electrical Equipment 50

3. Other 40

4) Fuel system 104

1. Operation 80

2. Maintenance 24

5) Others 10

1. Store 4

2. Vehicles 6

II. Professional and Management staff 90

Total number of staff 648


T. Labor Safety

593. The project will be constructed on the existing site of the CHP3, which is located in the southwest edge of UB urban area, so the neighboring environment will not be harmed by the project. The major concerns of safety will involve fire, explosion, electric shock, mechanical injury and fall danger. In order to ensure the safety during construction and operation, the following measures and principles should be taken.

1. Fire Prevention

594. In order to prevent fires, the project design takes into full consideration fire prevention programs and fire extinguishing systems, combined with practical and effective measures. The facilities should be designed taking into account different types of explosive sources and risk factors to take different anti-explosion measures, such as to control the accidents from the source point. In addition, during the production period, the operators shall be required to strictly follow safety procedures and implement all safety management measure to avoid fires and explosions from the source point.


Appendix 3-138

a. Fire Rating of Buildings

595. The fire rating of each building (construction) shall be designed in strict accordance with relevant design regulations. The basic components of each building (construction) should be designed to ensure adequate fire resistance performance. The mechanical design, anti-explosion decompression, ventilation safety precautions and safety evacuation of the workshop shall be implemented according to the code for fire protection design of buildings, such as building structure, fire bulkhead, girder, pillar, floor, suspending ceiling, roof, and trestle and so on.

b. Fire Distance of the Building (structure)

596. The safe distance between each building (structure) is one of the most important measures to prevent fire from spreading, to efficiently control fire and to minimize fire damages. The arrangement of production buildings, auxiliary plants and structures should be implemented according to relevant fire prevention rules for building design and technical specifications for thermal power plant design, as well as minimum allowance for spacing between each building (structure).

c. Fire Prevention of Main Power House

597. Reasonable separation of zones for fire prevention needs to be made. The turbine house and the deoxygenization room can be located within one fire zone. And the partition wall and the bunker bay should be designed to be fire resistant. The fire resistance of the partitions under the operation layer should be not less than four hours.

598. Coal and fuel oil are burned in the hearth. Because the framework for supporting boilers is part of butyl class fire hazard, in addition to equipping a fire fighting system and fire hydrants on each boiler’s major platform, an elevator shall be installed on each boiler to allow the staff to go from the bottom of each platform to the highest point of the boiler. There is a steel ladder on each left and right side of the boiler, which goes from the bottom of the furnace to the top of each platform. There are connecting pavements between each boiler and each platform of the coal bunker framework, which are convenient for patrol inspections, accident handling and personal evacuation.

599. Noncombustible materials are recommended to be used for decorating and partitions of central control rooms, electronic rooms and all classes of control rooms. Office accommodations should be made from noncombustible materials or flame retardant materials. It is recommended to control the storage quantities of combustibles to minimize fire potentials as well as consequent fire spreading.

d. Transportation inside the Main Plant

600. Establish the necessary vertical and horizontal clearances in the main power house, and the enclosed stairs on both ends and in the central part of the deoxygenization room, and for each story of the coal bunker room; producers and firefighters can use them once there is a fire.

e. Roads of the Whole Plant

601. The factory-in road design is based on the demands of the current “Code for design of road in factories and mining areas”; set driving roads and loop roads for fire truck between each building according to the demands of producing, life and fire control.

f. Fire Protection of the Whole Plant

602. It is important to design a comprehensive fire fighting system for the entire power plant and to follow relevant national policies, guidelines and standards. The “Prevention first” principal is to be applied and the relevant national standards and specifications shall be applied, for example, “Fire prevention rules for building design”, “Power plant and substation


Appendix 3-139

code for fire protection design”, and “Code for design of automatic fire sprinkler systems”. For important buildings and equipment, it is necessary to take the following measures: Set the outdoor fire hydrant extinguisher system in the plant area; set the indoor fire hydrant extinguisher system in major buildings (structures); adopt water spray extinguishing system for the transformer and oil system of the main power house; use a fixed foam extinguishing systems for the tank farm; use a fixed or half-fixed gas, self-extinguishing system for the important equipment rooms of the central control tower; set mobile fire extinguishers according to “Code for design of extinguisher disposition in buildings”.

g. Fire Prevention for Oil System

603. It is extremely important to enforce fire prevention and management standards for the steam turbine oil system, the fuel storage tank of the transformer and the ignition tank. In addition, it is important to take effective measures for leak and spill control for all oil pipelines, for example, to add white metal protective layer outside the insulating layer on the thermal pipeline in junction between the oil pipeline and the steam pipeline for prevention of fire in case of oil spills.

h. Fire Prevention of Electric Accessory and Cable

604. In strict accordance with the “Thermal power plant, substation DC system design technical regulations”, the facility should use cable fireproofing design and take reliable fire prevention and anti-flaming measures.

2. Anti-explosion

605. In order to mitigate explosion risk, the following measures should be taken:

Set security monitoring protection device in the boiler furnace for preventing explosions, as well as fire-extinguishing protection facilities. Set necessary explosion-proof doors and safety gates following regulations on boiler body, pulverizing system and high-pressure bottle.

Pressure vessel manufacturer should possess design and fabrication qualification certifications; inspect the anti-explosion facilities of explosive equipments terminally, such as high-pressure pipeline, pressure vessel, deaerators and so on.

Set ventilating devices in battery rooms, hydrazine dosing rooms, chlorine dosing rooms and so on; adopt explosion-proof electric facilities.

In strict accordance with relevant national standards, regulations and specifications during the design time of hydrogen generation stations.

3. Mechanical Injuries and Crash Prevention

606. Statistic data shows that most of casualty accidents are caused by mechanical injury during maintenance. Therefore, the staff should follow safety procedures during operation and overhaul, including:

Rotating elements of the machine are equipped with shields or other protective equipment (such as a fence). The exposed shat ends are equipped with protecting in case of rolling clothes in.

Equipments and valves, which need maintenances and operations in high-altitude, are all equipped with platforms and staircases.

All channels and holes are equipped with cover plates; set handrails on the holes for protection which can’t be closed.

Design with enough lighting in the main power house, construction, factory-in roads, coal handling system and cable galleries to prevent injuries during maintenance and operation at night.


Appendix 3-140

For the remote control electromotor, install emergency press-buttons locally to guarantee person and equipment safety, the vehicle can stop at any time in case of emergency.

Take measures against mechanical damage to rotary mechanical equipments, all the exposed mechanical rotation parts are equipped with shields or protective barriers.

Design and produce platforms, staircases and handrails strictly according to national corresponding standards to avoid falls.

Device platforms, hanging objects holes and staircases on the basis of design specification, allocate reliable handrails and skirting boards. Set repair and maintenance work platforms and galleries on the valves, hole covers, explosion doors and thief hatches, which contain maintenance and operation parts. All the stairs, steel ladders, platforms and walking boards take anti-skidding measures. All passageways of all classes of pits, holes, wells and channels set cover plates and fences to prevent staff from falling.

Aerial work must equip reliable safety belts and helmets.

4. Other Safety Precautions

607. Device Anticorrosion. Device anti-corrosion design shall include all kinds of chemical water treatment facilities including filters, wash tanks, high (low) acid (alkali) storage tank, picking dispensing cabinets and the rubber anticorrosion measures shall be taken. The anticorrosion measures are to be taken for heat exchangers in alkali liquor steam heater and reverse osmosis system to use stainless steel materials. Anticorrosion coating shall be applied for water tank with condensed water. 608. Pipe Anticorrosion. Rubber or plastic anticorrosive pipe materials are to be used in most of the water pipelines of the make-up water treatment system. Alkali and acid base pipelines are lined with steel. Resin transportation pipes and water vapor sampling tubes are to use stainless steel materials. Pipes adding sodium hypochlorite are to use polyethylene composite materials.

609. Floor and Drainage Ditch Anticorrosion. Drainage ditch for acid-base wastewater generated in the chemical water workshop is to be installed with corrosion resistance stone materials. The epoxy fiber reinforced plastic (FRP) is to be used for high acid (alkali) library terraces, acid-base pipe ditches and relevant equipment foundation. Ektexines of the acid-base equipment, ladders, and supports are to adopt chlorosulfonated polyethylene for anticorrosion.

610. Crane Inspection/Repair Facilities, Platforms and Galleries’ Settings. To provide a safer working environment, a crane inspection and repair facility is to be installed in the main workplaces, such as turbine house, boiler and bunker bay, all of auxiliary shops (circulating water pump house, ash removal pump house, air compressor room and crude oil engine room and so on).

611. Main and auxiliary engines in the main power plant are to be provided with sufficient overhaul space; for the larger sized rotating machines needing frequent maintenance, a maintenance platform, installation areas, travel galleries and passages for maintenance are to be designed. 612. Safety Signs and Colors. According to the relevant provisions regarding “Safety color” and “Safety sign”, all places, equipments and facilities that are dangerous and harmful to staffs are equipped with safety warning signs or coated with safety colors. 613. Safety Lighting. The emergency lighting has been designed for the Project, including light provided by alternative and direct current. In the main power plant, each machine is to be equipped with emergency lighting. Lighting power is provided by public security power supply of 380/220V. During normal operation, lighting power is supplied by the station serviced main


Appendix 3-141

bus bar. In case of power failure, lighting power is to be supplied by an alternative accident safety power source. Direct current accident lighting is supplied by reserved battery DC bus in unit control rooms, battery rooms and diesel engine rooms and so on.

614. In addition, an emergency light is installed in the important passageways and workplaces far away from the main power plant.

U. Occupational Health

1. Analysis of Harmful Occupational Factors

615. Dust. Dust is generated during loading and unloading, delivery, storage and preparation process of coal, limestone and ash, which makes negative impacts on workers and pollutes the environment. The systems which are easy to produce dust include coal handling system, ash disposal system and desulphurization limestone powder’s unload and deliver system.

616. Dust is generated during coal handling relating to coal unloading devices, delivery and transport links, scuttle’s coaling, and coal bunker room adhesive layer. Dust is generated during ash disposal relating to precipitator dust bucket export, discharge port of the dry ash-gallery. 617. Noise and Vibration. Noise and vibration are generated by rotation equipment, such as the coal breaker, steam turbine, blast engine and draft fan. In addition, noise is produced in places relating to boiler ignition exhaust steam, exhaust steam of the exit, feed pump and water circulating pump.

618. The vibration-producing areas include foundation and steam pipes of the steam turbine generator units.

619. High Temperature and Humidity. High temperature places relate to main power plant chiefly, damp-prone places (underground facilities of the coal handling system chiefly), as well as unloading coal grooves and underground forwarding station

620. Chemical Factors Chemical water treatment system produces poisonous and harmful gas during operation in the power plant; SF6 gas and fire resistant oil and other substances could make negative impacts on operator’s health.

621. Places which are easy to produce noxious gas include acid and alkali meter rooms, dosing rooms and liquid ammonia areas.

2. Occupational Health Prevention Measures

Dust Prevention

The coal handling system’s forwarding station, coal breaker rooms and bunker bay blanking points are all equipped with ash handling equipments, whose electric accessory enclosure grade of protection is IP54, and set ventilate devices.

Water flusher is equipped on the ground of each building of the coal handling system.

Retrofit buffer latch devices to the high fall coal spout, junction of each coal spout is equipped with a gasket seal, and the cloth curtain in the exit of the feed channel to prevent dust explosion.

Water spay dust suppression systems are set all around the coal yard. Spray water regularly on the coal heaps for preventing spontaneous combustion because of long term accumulation.

Improve greening of the plant area, plant appropriate trees and bushes on the two sides of the plant area roads and around the coal yard, which has some effect on reducing dust pollution.


Appendix 3-142

Comprehensive utilization is considered on dusting in the power plant; adopt dry dusting concentrated phase transport system and closed cars for delivering ash, and take measures on the loading cars for preventing fine ash escaping.

Lime preparation and such system set ash handling equipment; adopt better leak-proof equipment to deliver lime powder.

Gas Defense

Store and place equipment (bottles, tanks) that produce harmful substance into secure places such as water treatment workshop, hydrazine holding tank; moreover the storage room should set mechanical exhaust devices.

Acid-base buffer storage area and metering plant set water washing device.

Set acid fog absorbing mouth on the top of the acid tank, as well as automatic security shower in the acid-base storage area.

Power distribution unit and overhaul rooms of SF6 electric installation should set mechanical exhaust devices and SF6 gas purification recovery package should be equipped.

622. Chemical Injury Prevention. In order to prevent injuries related to chemicals, the following measures can be taken:

To select anticorrosive material or lined coating material in relation to chemical process equipment, acid-base storage tank, sewage treatment equipment and related pipes as well as accessories.

To take anticorrosion measures in relation to chemical treatment areas, sewage treatment areas, battery room’s terrace, wall space and pipe ditch.

To prevent boiler from corrosion during shut-down, for example, a coupled ammonia maintenance might take about one month.

623. Noise Protection. Noise prevention of the project plans to use comprehensive method: first control from the sound source, adopt effective sound insulation, noise mitigation, sound absorption and anti-vibration measures. Noise in the workplace and work environment of the operator on duty should be controlled below the specified limits in Table 6.29.

Table 6.29: Hygienic Standard for Industrial Noise

Day contact noise time (h) Limits [dB(A)]

8 85

4 88

2 91

1 94

1/2 97

1/4 100

1/8 103

Maximum may not exceed 115 [dB(A)]

624. Anti-vibration. Relevant vibration reducing measures to be taken for civil foundation of large-scale rotating equipments such as steam turbine generator unit, steam feed pump and coal breaker, air-pipe and building envelope of the control room in the centralized control multiple-use building and connection between floors. The designs to consider vibration reducing measures in relation to running parts of the equipment.


Appendix 3-143

625. Anti-freezing. The project is to install a centralized heating system to prevent the main power houses, auxiliary buildings and main affiliated accessory buildings from freezing. In addition, a shelter is recommended to be installed for cooling tower. During winter time, some shelter can be closed to reduce the cold air flow rate into the cooling tower and mitigate the freezing potential of the cooling tower.

626. Heatstroke Prevention. For guaranteeing good work performance and preventing workers from scalding, to establish heatstroke prevention and insulation procedures associated with pipes and equipments with high temperature exceeding 50°C.

627. The designs to consider ventilation measures in each building, such as natural air inlet of the main power house, mechanical exhaust, natural ventilation of the belt layers in coal rooms and machinery into exhaust in the low voltage switch rooms of electric.

628. To establish cooling ventilation system and air-condition facilities in all central control rooms as well as assistant rooms, local control rooms and night shift rooms. For super high temperature work environment, to install window-type air conditioners (such as turbine hall overhead crane).

629. Others Issues. In accordance with the relevant provisions, the power plant is to establish a labor protection basic monitoring station and safety education rooms.

630. The design of health facilities such as production/life/woman health rooms, medical treatment and public health organizations is to established in accordance with the requirement of related regulations and codes.

631. Crane, elevator, lifting appliance for maintenance are to be selected in accordance with relevant provisions to mitigate labor intensity.

V. Analysis of Energy-Saving

632. Energy consumption types of the coal-fired thermal power plant mainly include coal, light diesel, and electric energy. Energy conservation shall be considered through the entire process of project planning, design, operation, and management. Energy conservation works include three aspects: one is aimed at boilers, steam turbines, generators, and major auxiliary engines, with a view to enhancing main equipments’ thermal efficiency and reducing auxiliary equipments’ electricity consumption, thus achieving its energy-saving purpose. The second is aimed at technology systems, with a view to optimizing and perfecting the technology systems and facilities; improving operations and operating efficiencies; achieving energy-saving goals. The third focuses on adopting energy-saving new techniques with obvious effects, such as efficient CFB, variable frequency technology used in auxiliary equipments, and so on. The project’s main energy-saving measures are as follows:

1. Optimize Technology System Designs

Adopt equipment with better parameters of high thermal efficiency, low coal consumption and high reliability.

The design to introduce energy-saving technology, to eliminate high energy-consumption, low-efficiency equipment, and outdated products.

Boiler circuit to use unit system for connection, including fixed-slip-fixed mode for operation and a set 40% volume BMCR (tentative) bypass, as to save steam for pre-heating system and to recover working medium after start up. To shorten the start-up time would achieve a notable energy-saving effect.

System design should consider steam and water recovering or reuse. Set hydrophobic expending devices, collect pipe drain generated from start-up, shut-down and operation, then the water enter into release gear/condenser, so as to recover working medium.


Appendix 3-144

Effective measures to reduce boiler coal consumption include keeping the hearth as well as the rear heating surface clean and enhancing the heat transfer efficiency. Therefore, during the boiler body’s design, reliable and integrated soot blowing system is equipped so as to regularly use soot blower during operation and keep the heating surface clean.

The electronic weighing coal belt feeder can help calculate the coal consumed accurately that enter into each boiler, as for efficient economic accountings.

Optimize the setting of flue gas, air and coal pipelines to reduce local resistance loss and save electricity consumption.

Select high performance thermal insulation material so as to reduce heat loss and improve operation environment.

Under the technical and economic reasonable circumstance, adopt new type of energy-saving electric accessory with high efficiency and low consumption such as main transformer, high and low voltage transformer, reserve/starting transformer, which are all low consumption and energy-saving transformers.

Optimize piping layout inside and outside the factory, reducing system resistance and electricity consumption.

Optimize electrical system design, rationally scheme electric accessory arrangement, and cable, reducing cable and voltage loss.

Electromotor of driving rotating machines should adopt low consumption and high efficiency products.

To select electric cables as well as wires to consider economic conditions.

Expand the scope of natural ventilation and natural lighting during construction lighting and ventilation design, in meeting relevant regulations and standards. Arrange air vents in the walls and floors rationally to avoid airflow short circuits and backflows, and reduce airflow dead angles.

To reduce travel links of the coal handling system and select high efficiency energy-saving equipment and motors, so as to achieve the purpose of saving and optimally using energy.

2. Equipment Selection

Priority to be given in selection of adjustable rotor blade axial fan for pressurized fan, and static leaf adjustable axial fan for draught fan, to ensure high efficiency and power saving;

Adopt 3-50% capacity condensate pump, reduce electricity consumption during unload operation;

Adopt water-saving and energy-saving slag-removal equipment such as slag remover;

Select belt conveyor and drive motor reasonably so as to save energy;

To select high efficiency motor so as to improve motor’s productiveness and energy saving; and

To select high energy efficiency chiller

3. Energy-saving in Buildings and Lower Energy Consumption Measures

633. Buildings of the project can achieve the purpose of energy-saving and lower energy consumption by means of applying in lighting, thermal insulation and materials, and so on. 634. Lighting. All main workshops are recommended to use natural lighting and be


Appendix 3-145

supplemented with artificial lighting when necessary. The central control rooms are recommended to use artificial lighting. All indoor lighting is recommended to use natural lighting combined with artificial lighting, avoiding using high lighting and inefficient lamps and equipments. 635. Insulation for maintenance structure. All exterior walls is recommended to use color double-layer composite steel for maintenance structure and inner wall is recommended to use 200 mm thick light concrete blocks.

636. Steam turbines are recommended to adopt corrugated steel sheet bottom-formwork reinforced concrete with molecular waterproofing materials and plastic extruded board insulation roofs. Other reinforced concrete roofs are recommended to adopt plastic extruded board insulation and waterproofing materials.

637. Material Utilization. To follow recycle-reuse-renewable principal for material utilization and to use materials that consumes minimum amount of energy in the process of production. For example, the exterior walls is recommended to adopt recycled corrugated steel sheet to minimize the application of bricks for energy conservation.

638. To select wear-resistance and easy-cleaning materials for floor designs, for example, wear-resistance terraces and cement plasters. 639. Other Auxiliary Buildings. To arrange auxiliary buildings accessible and convenient for major production use. The buildings shall be designed to make full use of natural light and to have a reasonable window to floor and wall ratios. The reinforced plastic windows shall be designed for better insulation performance. A compact abdomen steel storm door is to be designed for energy saving.

640. Roofing designs include armored concrete slabs consisting of synthetic high polymer sheet waterproof layers and extruded sheet insulation layers. Outer wall designs include aerated concrete. Floor design features include wear resistant, easy to clean up, energy-saving, wear-resistance terraces and cements during construction and operation periods, and part of non-slippery tiles.

4. Energy Saving and Consumption Indexes

641. With the implementation of the above-mentioned measures, the thermal efficiency, coal consumption and power consumption will meet relevant energy efficiency standards, as shown in Table 6.30 below:

Table 6.30: Energy Efficiency Indexes

No. Item Unit Indicator

1 Average annual generation standard coal consumption g/kWh 263

2 Average annual heating standard coal consumption Kg/GJ 38.7

3 Integrated auxiliary power rate % 10

4 Annual thermal efficiency of the whole plant % 59.5

5 Average annual thermoelectric ratio % 84.5


W. Project Implementation Schedule

642. The CHP5 project implementation schedule has been developed describing all major project implementation activities over a 10-year project implementation period from 2010 through 2020. As scheduled, the project is to be constructed in two phases, including Phase I which is scheduled to be completed by 2015, and Phase II which is scheduled to be completed by 2020. The project implementation schedule covers four major project


Appendix 3-146

implementation stages with indicative milestones to ensure that the project is implemented within a planned timeframe: i) project preparation, ii) pre-construction, iii) procurement, and iv) construction and commissioning.

643. The construction season is relative short in Mongolia due to long-winter season. Thus, some tasks must be performed in parallel and well coordinated in order to meet the target of completing Phase I by 2015. The project implementation plan for both Phase I and Phase II are illustrated in Figure 6.16.

1. Stage 1: Project Preparation

644. Under the project preparation stage, several key project activities are to be undertaken, including completion of feasibility study report and environmental impact assessment impact (EIA) report and obtaining approvals; bidding document preparation for EPC or BOT depending on the Government’s decision on how to finance the project; bidding process completion and contract awarding; preliminary design and design review; and detailed engineering design.

645. This report covers feasibility study of the CHP5 project and it includes demands forecast, power plant justification, proposed plant size and technology, heat supply system analysis, site selection and surveys, coal analysis, master planning of the plant site, main equipment design, power supply system, thermodynamic system, combustion system, water supply system, control system, civil works, heating, ventilating, and air-conditioning (HVAC), pollution countermeasures, energy efficiency, water conservation and materials conservation measures, fire protection and safety, environmental impact assessment, social impact assessment, public consultation, financial analysis, and economic analysis. The feasibility study and EIA preparation are scheduled to be completed in the first quarter of 2011.

646. Bidding document preparation, preliminary design and detailed engineering design are also parts of the major project implementation activities during Stage 1. The bidding document preparation task may have different contents depending on whether PPP model will be adopted or not. Under the EPC option, bidding document should include technical specifications, bill of quantities, and engineering drawings in full compliance with the international practices and national bidding procedures. It will also include pre-bid conference, clarification during bidding, bid opening, bid evaluation, and bid awards. The bidding and engineering design tasks are scheduled to be undertaken during May 2011 to April 2013 for Phase I and June 2016 to April 2018 for Phase II.

647. The project preparation tasks under Phase I are scheduled to be completed by April 2013. The project preparation tasks under Phase II are scheduled to start in March 2016 and complete by April 2018.

2. Stage 2: Pre-construction Preparation

648. Under the project pre-construction tasks, several key project activities are to be undertaken, including power supply arrangement, communication facilities and initial civil works and site preparation. The pre-construction tasks are scheduled to be undertaken during February to April 2013 for Phase I and February to April 2018 for Phase II.

3. Stage 3: Procurement

649. The procurement activities include finalization of bidding documents, contract negotiation, and purchasing of equipment and delivery. Bidding document preparation and finalization tasks are scheduled to start in June 2011 and complete in September 2011 for Phase I. Bidding document preparation and finalization tasks are scheduled to start in May 2017 and complete in September 2017 for Phase II. Tendering, contract negotiation and contract award will be undertaken during October 2011 to March 2012 for Phase I. Tendering, contract negotiation and contract award and will be undertaken during February 2018 to July 2018 for Phase II. The procurement activities are scheduled to start in January


Appendix 3-147

2012 and complete in May 2013 for Phase I. The procurement activities are scheduled to start in May 2017 and complete in July 2018 for Phase II.

4. Stage 4: Construction and Commissioning

650. The tasks at Stage 4 include construction of auxiliary facilities for high-pressure part of CHP3 and Phase I; decommissioning of existing auxiliary facilities of CHP3; relocation of pipelines, grid, and associated facilities; civil works for main plant, coal yard and associated facilities; installation of major equipment and auxiliary facilities; and plant commissioning.

651. Construction of auxiliary facility for HP part and Phase I is scheduled to start in April 2013 and complete in November 2013. The decommissioning of existing auxiliary facilities of CHP3 is planned to start in July 2013 and complete in November 2013 for Phase I. The decommissioning of existing auxiliary facilities of CHP3 is planned to start in May 2017 and complete in December 2017 for Phase II. The relocation of pipelines, grid and associated facilities is planned to start in July 2013 and complete in November 2013 for Phase I. The relocation of pipelines, grid and associated facilities is planned to start in April 2017 and complete in October 2017 for Phase II. Civil works for main plant and coal yard is planned to start in June 2013 and complete in August 2015 for Phase I. Civil works for main plant and coal yard is planned to start in April 2018 and complete in September 2020 for Phase II. Civil works for preparing coal ash yard is scheduled during April – September 2014.

652. Installation of major and associated equipment is planned to start in March 2014 and complete in October 2015 for Phase I. Installation of major and associated equipment is planned to start in March 2019 and complete in October 2020 for Phase II. Commissioning for Phase I is planned to start in July 2015 and complete in December 2015. Commissioning for Phase II is planned to start in June 2020 and complete in November 2020.

653. The construction of Phase I of the Project is scheduled to start in April 2013 and complete in December 2015 while that for Phase II is scheduled to start in May 2017 and complete in November 2020.


Appendix 3-148

Figure 6.16: Project Implementation Schedule


A S OND J FMAM J J A SOND J FMAM J J A S OND J FMAM J J A SOND J FMAM J J AS OND J FMAM J J A SOND J FMAM J J AS OND J FMAM J J A SOND J FMAM J J AS OND J FMAM J J A SOND J FMAM J J AS ON D

Project Preparation ActivitiesFeasibility Study and EIA Preparation andApproval

Funding and Loan Effective DateBidding Document Preparation for EPC orBOT

Bidding Process

Bid Evaluation and Contract Award Preliminary Design and Review Detailed Engineering Design

Pre-Construction Activities

Power Supply Arrangement

Communication Facilities

Initial Civil Works and Site Preparation Procurement Activities

Finalization of Bidding Documents Contract Awarding and Negociation

Project Implementation Construction of Auxiliary Facility for HP Partand Phase IDecommiss ioning of exisitng auxiliaryfacilities of CHP3Relocation of Pipeline, Grid, and AssociatedFacility

Civil Work for Ash YardCivil Work for Main Plant, Coal Yard, andothers

Installation of main and auxiliary equipments

Plant Commission

Stage of Engineering Major Activities Milestone of the key stage Sub Milestone of the activy

Task NamePhase I Phase II

2017 2018 2019 2020201620132011 20122010 20152014