basic survey project for joint implementation, etc.' for
TRANSCRIPT
NEDO-IC-OOER39
“The Basic Survey Project for Joint Implementation, Etc."
for
Revamp Study
on
Feedstock Change and Energy Saving
m
India Fertilizer Plants
March, 2001
New Energy and Industrial Technology Development Organization(NEDO)
Entrusted to Toyo Engineering Corporation, Japan
020 005042-5
The Basic Survey Project for Joint Implementation, Etc.
Revamp Study on Feedstock Change and Energy Saving in India Fertilizer Plants
Toyo Engineering Corporation
March, 2001
This feasibility study has been conducted under the program of “The Basic Survey Project
for Joint Implementation, Etc.” which aims to identify studies concerning the Joint
Implementation (JI) and the Clean Development Mechanism (CDM) to which Japan’s
technologies for energy conservation can be applied to reduce emissions of greenhouse
performance gases. This feasibility study has been conducted in order to identify studies
concerning “Clean Development Mechanism (CDM)” for the Revamp Study on
Feedstock Change and Energy Saving in India Fertilizer Plants which is under planning by
Zuari Industries Limited (Fertilizer Division) in Goa, India.___________________________
NEDO-IC-OOER39
"The Basic Survey Project for Joint Implementation, Etc."
for
Revamp Study
on
Feedstock Change and Energy Saving
m
India Fertilizer Plants
March, 2001
New Energy and Industrial Technology Development Organization(NEDO)
Entrusted to Toyo Engineering Corporation, Japan
INTRODUCTION
This feasibility study has been conducted under the program of “The Basic Survey Project for Joint
Implementation, Etc.” which aims to identify studies concerning the Joint Implementation (JI) and
the Clean Development Mechanism (CDM) to which Japan’s technologies for energy conservation
can be applied to reduce emissions of greenhouse performance gases. For this purpose, the
implementation of feasibility studies are entrusted to such Japanese corporations who have
potential projects and are aspiring to execute the projects.
This feasibility study report on the revamp study on feedstock change and energy saving in India
fertilizer plants has been prepared by Toyo Engineering Corporation, to which the feasibility study
were entrusted from NEDO as of September 1,2000.
March, 2001
Team Leader, T.Mii
CONTENTS
ABBREVIATION
LIST of FIGURE and TABLE
SUMMARY, CONCLUSION AND RECOMMENDATION
CHAPTER 1 PROJECT BACKGROUND
1.1 Information on India................................................................................ 1-1
1.1.1 Political, Economy and Social Status............................................... 1-1
(1) Political Status
(2) Economy Status
(3) Social Status
1.1.2 Energy Strategy...................................................................................... 1-13
(1) Crude Oil
(2) Natural Gas
(3) Coal
1.1.3 Needs of Clean Development Mechanism (CDM) ..................... 1-22
1.2 Necessity of Technology Introduction for Energy Saving • • • 1-23
1.3 Purpose, Need and Effect of the Project........................................ 1-24
1.3.1 Purpose of the Project........................................................................... 1-24
1.3.2 Need of the Project............................................................................... 1-24
1.3.3 Effect of the Project............................................................................. 1-25
CHAPTER 2 PROJECT PLANNING
2.1 Project Plan............................................................................................... 2-1
2.1.1 Site Information...................................................................................... 2-1
(1) Location and Topography
(2) Geology
(3) Meteorological Conditions
-1 -
2.1.2 Project Concept ...................................................................................... 2-4
2.1.3 Greenhouse Performance Gas to be examined ............................... 2-5
2.2 Outline of Zuari Industries Limited (ZIL)....................................... 2-6
2.2.1 Intention of ZIL........................................................................................ 2-7
2.2.2 Conditions and Status of Related Infrastructure and Facilities 2-8
2.2.3 Performance of Project Execution...................................................... 2-31
(1) Engineering Performance
(2) Management Organization
(3) Management Foundation and Management Policy
(4) Financial Performance
(5) Human Resources
(6) Project Execution Organization
2.2.4 Outline of the Project.............................................................................2-35
(1) Design Basis
(2) Outline of the Plant
(3) Plant Layout
(4) Plant Cost
(5) Raw Materials and Utilities Consumption
2.2.5 Scope of Supply.........................................................................................2-71
2.2.6 Conditions and Issues for Project Execution................................. 2-73
2.2.7 Project Execution Schedule..................................................................2-73
2.3 Financing Plan...........................................................................................2-75
2.3.1 Financing Plan for Project Execution............................................... 2-75
(1) Required Fund
(2) Debt/Equity Ratio
(3) Financing Plan
2.3.2 Conceptual Financing Plan....................................................................2-77
2.4 Conditions for Clean Development Mechanism (CDM)......... 2-78
2.4.1 Coordination Issues for Project Materialization.......................... 2-78
2.4.2 Possibility that India consents to apply CDM............................... 2-78
CHAPTER 3 EFFECTS OF PROJECT
3.1 Effects on Energy Saving...................................................................... 3-1
3.1.1 Technical Background........................................................................... 3-1
3.1.2 Baseline....................................................................................................... 3-2
3.1.3 Quantitative Effects............................................................................... 3-3
3.1.4 Review and Confirmation...................................................................... 3-5
3.2 Reduction of Greenhouse Performance Gas..................................... 3-6
3.2.1 Technical Background..............................................................................3-6
3.2.2 Baseline...................................................................................................... 3-6
3.2.3 Quantitative Effects............................................................................... 3-8
3.2.4 Review and Confirmation.......................................................................3-10
3.3 Affects to Productivity......................................................................... 3-11
CHAPTER 4 PROFITABILITY
4.1 Financial Evaluation............................................................................... 4-1
4.1.1 Evaluation Method for Profitability................................................. 4-1
(1) Without Revamp (without case)
(2) With Revamp (with case)
(3) Evaluation for Revamp project
4.1.2 Required Fund........................................................................................... 4-2
(1) Basic Conditions of Calculation
(2) Erection Cost
(3) Pre-production Cost
(4) Initial Working Capital
(5) Interest during Construction
(6) Total Investment Cost
4.1.3 Operation of Plant.................................................................................... 4-6
(1) Production and Sales Plan
(2) Required Number of Employees
(3) Training Plan
(4) Recruiting Plan
(5) Variable and Direct Fixed Cost
-3 -
(6) Production Cost
4.1.4 Financial Evaluation............................................................................... 4-17
(1) Conditions of Financial Evaluation
(2) Financial Statements
(3) Financial Internal Rate of Return (FIRR)
(4) Sensitivity Analysis on ROI before Tax
(5) Evaluation
4.2 Cost versus Effects................................................................................. 4-31
4.2.1 Cost versus Energy Saving Effect...................................................... 4-31
4.2.2 Cost versus Greenhouse Performance Gas Reduction................... 4-31
CHAPTER 5 SPREAD EFFECTS
5.1 Spread Possibility of the Applied Technology in other area •• 5-1
5.2 Effects under Spread Consideration................................................. 5-2
5.2.1 Effects on Energy Saving...................................................................... 5-2
5.2.2 Effects on Greenhouse Performance Gas Reduction........................5-3
CHAPTER 6 EFFECTS to OTHERS
6.1 Environmental Effects........................................................................... 6-1
6.2 Economical Effects................................................................................. 6-2
6.3 Social Effects............................................................................................. 6-3
CONCLUSION and RECOMMENDATION
ATTACHMENT
Reference List
-4-
Project Team Member List
Name Role and Major Works Company
T. MiiProject Team Leader
General and Project Background
Toyo Engineering
Corporation
H. NakamuraProject Planning and Effects, Spread Effects
(Ammonia)
Toyo Engineering
Corporation
M. UchiyamaProject Planning and Effects, Spread Effects
(Ammonia-Assistant)
Toyo Engineering
Corporation
S. HiroseProject Planning and Effects (Ammonia-
Assistant)
Toyo Engineering
Corporation
H. MorikawaProject Planning and Effects, Spread Effects
(Urea)
Toyo Engineering
Corporation
Y. KojimaProject Planning and Effects, Spread Effects
(Urea-Assistant)
Toyo Engineering
Corporation
H. FujiiProject Planning and Effects (Urea-Assistant) Toyo Engineering
Corporation
Y. IkawaProject Planning and Effects, Profitability
Analysis, Spread Effects
Toyo Engineering
Corporation
S. YamazakiBasic Design of Facilities (Layout & Piping),
Project Planning and Effects
Toyo Engineering
Corporation
S. WatanabeBasic Design of Facilities (Layout & Piping -
Assistant), Project Planning and Effects
Toyo Engineering
Corporation
Y. KawamotoBasic Design of Facilities (Vessel), Project
Planning and Effects
Toyo Engineering
Corporation
Y. WadaBasic Design of Facilities (Rotating Machine),
Project Planning and Effects
Toyo Engineering
Corporation
A. NaitoBasic Design of Facilities (Furnace), Project
Planning and Effects
Toyo Engineering
Corporation
T. SugitaBasic Design of Facilities (Material handling),
Project Planning and Effects
Toyo Engineering
Corporation
H. FurukawaBasic Design of Facilities (Instrumentation),
Project Planning and Effects
Toyo Engineering
Corporation
M. KuninagaBasic Design of Facilities (Electrical), Project
Planning and Effects
Toyo Engineering
Corporation
T. UenoBasic Design of Facilities (Civil &
Architectural), Project Planning and Effects
Toyo Engineering
Corporation
H. SatoProject Background, Market Survey, Project
Planning
Toyo Engineering
Corporation
H. EbisawaPlant Cost Estimation (Summary) Toyo Engineering
Corporation
S. KawakamiPlant Cost Estimation (Equipment) Toyo Engineering
Corporation
Y. OnodaFinancing Plan, Project Coordinator Toyo Engineering
Corporation
H. HeyaProject Background, Market Survey, Project
Planning (Part time)
Toyo Engineering
Corporation
ABBREVIATION
A Monetary
INR(or Rs)Indian Local Currency, Rupee
US$ U.S. Dollar
MUSS Thousand US$
MMUSS Million USS
JPY Japanese Yen
MMJPY Million Japanese Yen
LAKH 100,000
CRORE 10,000,000
B. Contract
C&F Cost and Freight
CIF Cost, Insurance and Freight
FOB Free on Board
LSTK Lump Sum Turn Key
C. Organization
1. India
ZIL Zuari Industries Limited
CFCL Chambal Fertilizers and Chemicals Limited
GAIL Gas Authority of India Limited
CIL Coal India Ltd
SCCL Singareni Collieries Company Ltd
IOCL Indian Oil Corporation Limited
ONGC Oil and Natural Gas Corporation Ltd
2. Others
MET! Ministry of Economy, Trade and Industry
NEDO New Energy and Industrial Technology Development Organization
JBIC Japan Bank for International Cooperation
-1 -
ADB Asian Development Bank
WTO World Trade Organization
TEC Toyo Engineering Corporation, Japan
KBR Kellogg Brown & Root, Inc., U.S.A
TEIL Toyo Engineering India Ltd., India
D. Unit
1. Length
cm centimeter
km kilometer
m meter
mm millimeter
2. Area
cm2 square centimeter
ha hectare
km2 square kilometer
m2 square meter
3. Volume
cm3 cubic centimeter
L, 1
m3
liter
cubic meter
Nm3 normal cubic meter at 0°C, 1 atm
Sm3 standard cubic meter at 20°C, 1 atm
bbl barrel
mmSm3 mil ion standard cubic meter at 20°C, 1 atm
MCM thousand cubic meter
4. Weight
g gram
kg kilogram
mg milligram
T, t, ton metric ton
Tonne metric ton
-2-
Time
Y,y year
M,m month
D,d day
h, hr, H, Hr hour
min minute
s, sec, S second
Capacity and rate
kg/h kilogram per hour
m3/h cubic meter per hour
t/h metric ton per hour
t/y metric ton per year
t/d metric ton per day
MTPD metric tonne per Day
BPSD barrel per stream day
Pressure
A absolute
G gauge
Pa pascal
kPa kilo-pascal
Mpa mega-pascal
atm atmospheric pressure
kg/cm2 kilogram per square centimeter
mmHg millimeter of mercury column
Temperature
°C degree Celsius (centigrade)
Energy
cal calorie
kcal kilocalorie
Gcal gigacalorie
kWh kilowatt hour
MWh megawatt hour
-3-
10. Power
kW kilowatt
MW megawatt
11. Others
Hz Hertz (frequency)
k kilo (1,000)
kV kilovolt (voltage)
m milli (1/1,000)
M thousand (Roman) or mega (1,000,000)
MM million (Roman)
MW Molecular Weight
% percent
ppm parts per million
Economics
CIRR Commercial Interest Reference Rate
DCF Discounted Cash Flow
EIRR Economic Internal Rate of Return
FC Foreign Currency
FIRR Financial internal Rate of Return
FP Foreign Portion
GDP Gross Domestic Production
GNP Gross National Production
IDC Interest During Construction
IRR Internal Rate of Return
LC Local Currency
LP Local Portion
ROE Return on Equity, IRR on Equity
ROI Return on Investment
VAT Value-Added Tax
-4-
F. Process
ACES Advanced Process for Cost and Energy Saving
KAAP Kellogg Advanced Ammonia Process
Miscellaneous
BFW Boiler Feed Water
BL Battery Limit
CW Cooling Water
DAP Di-Ammonium Phosphate
DM De-mineralized Water
EP End Point
F/S Feasibility Study
HBJ Hazira-Bijaipur-Jagdhishpur
IBP Initial Boiling Point
JSC Joint Stock Company
LNG Liquified Natural Gas
LPG Liquefied Petroleum Gas Propane and Butane
MAP Mono-Ammonium Phosphate
max. Maximum
min. Minimum
MOU Memorandum of Understanding
MSL Mean Sea Level
N/A Not Available or not applicable
NG Natural Gas
NGL Natural Gas Liquid
NPK Nitrogen Phosphate Potash
OSBL Out Side Battery Limit
vol. Volume
wt. Weight
-5-
LIST of FIGURE and TABLE
CHAPTER I
Fig. 1.1-1 Map of India
CHAPTER!
Fig. 2.2-1 Ammonia Simplified Flow Diagram (Existing)
Fig. 2.2-2 Simplified Ammonia Plant Steam Balance (Existing)
Fig. 2.2-3 Zuari Industries Limited Organization Chart Fertilizer Division
Fig. 2.2-4 Ammonia Simplified Flow Diagram (After Revamp)
Fig. 2.2-5 Simplified Ammonia Plant Steam Balance (After Revamp)
Fig. 2.2-6 Urea Process Renovation Scheme
Fig. 2.2-7 Urea C02 Compression Section
Fig. 2.2-8 Urea Hydrogen Removal
Fig. 2.2-9 Urea Synthesis Section
Fig. 2.2-10 Urea Purification Section
Fig. 2.2-11 Urea Recovery Section
Fig. 2.2-12 Urea Steam System
Fig. 2.2-13 Conceptual Figure of Existing Plant Layout in Zuari Industries
Limited (ZIL)
CHAPTERS
Table 4.1-1(1) Production and Sales Plan for Without Case
Table 4.1-1(2) Production and Sales Plan for With Case
Table 4.1-2 Variable Cost Summary at 100 % Operation
Table 4.1-3 Fixed Cost Summary
Table 4.1-4(1) Production Cost (Variable & Fixed Direct Cost) for Without Case
Table 4.1-4(2) Production Cost (Variable & Fixed Direct Cost) for With Case
Table 4.1-5(1) Income Statements (Profit and Loss Statements) for Without Case
Table 4.1-5(2) Income Statements (Profit and Loss Statements) for With Case
Table 4.1-6(1) Cash Flow Statement (Funds Flow Statement) for Without Case
Table 4.1-6(2) Cash Flow Statement (Funds Flow Statement) for With Case
Table 4.1-7(1) Project Balance Sheet for Without Case
Table 4.1-7(2) Project Balance Sheet for With Case
Table 4.1-8 Internal Rate of Return
CHAFFEH4 (coatmtie#
Fig. 4.1-1
Fig. 4.1-2
Fig. 4.1-3
Natural Gas Price vs ROI
Product Urea Sales price vs ROI
Total Investment Cost vs ROI
SUMMARY, CONCLUSION AND RECOMMENDATION
SUMMARY. CONCLUSION AND RECOMMENDATION
Information on India and Needs of the Project
The Indian economy is expected to grow by 5.9 per cent in 1999-2000. The
inflation rate dropped to international levels of 2 to 3 per cent for the first time in
decades. This was demonstrated by the continuing rise in foreign exchange
reserves and a relatively stable exchange rate.
The coal reserves of India is estimated as 211,600 million tonnes, which is the
sixth position in the world. Coal is used as energy source of about 60 % in India.
But most of power generation based on coal gasification become old and their
thermal efficincy is relatively low. The share of coal as energy supply in India
have been gradually dencreased. Crude oil production during 1998-99 was 32.7
million tonnes. The import of crude oil between April - November, 1999 was 31.5
million tonnes. The refining capacity has increased to 109.0 million tonnes per annum
making the country almost self-sufficient in the refining sector.
The production of natural gas during 1998-99 was around 75 mmSm3/D. The demand
of gas is of the order of 260 mmSm3/D and projections of gas demand indicate a wide
and growing gap between demand and supply. To meet this gap, the Government
have taken steps for import of natural gas from the Middle-East. The projects for
import of liquefied natural gas at Dahej and Kochi are being implemented by Petronet
LNG Limited.
C02 emission in India was fifth position in the world following U.S.A, China,
Russia and Japan. C02 emissions from petroleum and coal are dominant in the
total.
Population of India almost reaches one billion and is estimated to become above
China in near future. Therefore food, fertilizer, energy, social overhead capital
etc. should be increased. Most of fertilizers necessary for agricultural product have
been produced in India to secure domestic supply of food. The government of
India gives fertilizer sector subsidy to fix sales price of fertilizer to secure
domestic production.
Under such subsidy policy old fertilizer plants with less efficiency are still
operated and drastic improvement of fertilizer plants with feedstock of heavy
hydrocarbons such as coal, heavy oil, naphtha have been suspended. Therefore
production of fertilizer in India became less competitive compared with
international market. In order to improve such situation old fertilizer plants with
naphtha feedstock should be revamped to change feedstock to natural gas and to
reduce energy consumption, which are in compliance with the guideline of long
term policy on fertilizer sector being proposed by the government of India.
The fertilizer companies based on naphtha feedstock will suffer due to not only
reduction of subsidy, but also recent high naphtha price. Therefore old fertilizer
plants with naphtha feedstock should be revamped to change feedstock to natural
gas and to reduce energy for their survival. The necessity of technology
introduction for energy saving is very high in India.
2. Project Planning
Zuari Industries Limited (ZIL) in Goa, India produces ammonia with feedstock of
naphtha and also produces urea from ammonia and C02 produced in the ammonia
plant. These plants were constructed by Toyo Engineering Corp. (TEC) based on
TEC's own technologies and started the operation in 1973. The energy
consumption of these plants are considerably large compared with latest modern
plants and the ammonia plant uses expensive naphtha as feedstock and fuel.
These plants were ones of the largest, fully integrated, ammonia and urea complex
in India and Goa's first large industrial undertaking. ZIL expanded its fertilizer
plants by adding DAP (in 1984) in Goa. The fertilizers produced are supplied not
only to Goa, but also to Andhra Pradesh, Karnataka and Maharashtra.
The Project objectives are to reduce fertilizer production cost and to decrease
discharges of C02 gas into the atmosphere by feedstock change and energy saving.
The ammonia plant was constructed by Toyo Engineering Corporation based on its
Steam Reforming Process for producing ammonia starting with naphtha as feed.
The original design of ammonia production capacity was 660 metric tonnes per
-2-
stream day. The ammonia plant has been modified by ZIL to mainly increase the
production capacity.
The plant was originally designed to produce 1140 metric tons of prilled urea per
stream day by single train using MITSUI-TOATSU Total Recycle C process. The
plant has been debottlenecked by ZIL several times, since its stand-up, to have the
production capacity about 1300 - 1350 metric tons per day.
The energy saving and feedsrock change were studied in the F/S at the design
capacity for the study is 750 tons per day ±10 % for ammonia and 1,300 tons per
day ±10 % for urea.
The major applied technologies for the ammonia plant are listed below.
1) aMDEA process for C02 removal
2) KAAP converter installed in ammonia synthesis
3) High pressure condensate stripper
4) Modification of compressors and turbines
The feedstock change from naphtha to natural gas is also applied for the ammonia
plant and also can achieve energy saving.
TEC's ACES 21 is applied for the urea plant. ACES 21 is featured with
improvement of reaction efficiency and effective recovery of heat to reduce energy
effectively and economically.
EPC cost of the revamp plants was estimated as below.
Category Estimated Cost (MUS$)
Engineering 9,404
Equipment and Material 38,264
Construction 8,679
Others 2,530
Total Plant Cost 58,877
-3-
The raw material and utilities consumption of ammonia plant is summarized below
for before revamp, after energy saving and after feedstock conversion.
as per ton ammonia
before revamp after energy saving after feedstock change
Feedstock 5.501 5.389 5.611 Gcal
Fuel
Naphtha or NG 3.405 3.215 2.931 Gcal
Steam 0.775 -0.169 -0.411 Gcal
Power 0.110 0.170 0.166 Gcal
C.W 0.293 0.239 0.240 Gcal
sub-total 4.583 3.455 2.926 Gcal
Total 10.084 8.844 8.537 Gcal
The raw materials and utilities consumption of urea plant is summarized below in
comparison before and after renovation.
Existing Renovated
Steam (T/T)
Import 43.0 Kg/cnfG x 385°C 1.67 1.10
11.4 Kg/cm2G x 215°C 0.09 -
Export 21.5 Kg/cnrG x 318°C - -0.16
11.8 Kg/cnrG x 265°C -0.32 -
Net 1.44 0.94
Electricity (kWh/T)1} 86 77
Energy (Gcal/T)
Steam 1.101 0.717
Electricity 0.211 0.189
Total 1.312 0.906
Saving Base 0.406
Note 1} including power for cooling water
-4-
Project execution schedule is planned as follows.
Work Item Schedule
Evaluation on F/S by India side Application of Japanese fund etc.
Apr. 2001 — Feb. 2002
Start of EPC works Mar. 2002
Basic and detailed design Mar. 2002 — Feb. 2003
Construction of the plant and Tie-in Feb. 2003 - Jul. 2004
Pre-commissiong/commissioning Aug. 2004 — Sep. 2004
Start of commercial operation Oct. 1st, 2004
Required fund as Total Investment Cost is 60,832 MUSS, breakdown of which is
summarized below:
(UNIT: M US$)
ITEM ForeignCurrency
LocalCurrency Total
Erection Cost 40,678 18,200 58,877
Pre-production Cost 0 0 0
Initial Working Capital 0 0 0
Interest during Construction 0 1,954 1,954
Total Investment Cost 40,678 20,154 60,832
After discussions with India, the required finance plan for the project has been
presumed as follows:
- Debt 40,678 MUSS (66.9 %)
- Equity 20,154 MUSS (33.1 %)
JBIC export credit loan will be applied to economic evaluation of this project.
-5-
3. Effect of Project
Annual reduction of crude oil by energy saving of ammonia and urea plants is
55,705 toe/y.
Total quantity of the energy saving over the project life is 1,114,100 toe crude oil
equivalent as summarized below.
Total-Quantity of Energy Saving.
Period,Year Crude oil equivalent, toe/y Total Energy saving, toe
1st to 10th 55,705 557,050
11th to 20th 55,705 557,050
Total 1,114,100
Annual reduction of C02 of ammonia and urea plants is 245,139 t-C02/y.
Total quantity of the C02 reduction over the project life is 4,902,780 t-C02 as
summarized below.
Total Quantity of CQ2-Reduction
Period, Year C02 Reduction, CQ2/y
t- Total C02 Reduction, t-co2
1st to 10th 245,139 2,451,390
11th to 20th 245,139 2,451,390
Total 4,902,780
4. Profitability
250 US$/T as urea sales price, 333.43 US$/T as naphtha price (equivalent to 7.9
US$/MMBtu low heat value) and 6.0 US$/MMBtu (low heat value) are estimated
as FIRR calculation basis. The FIRR calculation results are shown below.
(a) FIRR on Investment (ROI)
Before Tax 35.21 %
-6-
After Tax 28.19 %
(b) FIRR on Equity (ROE)
Before Tax 63.68 %
- After Tax 49.78 %
According to the sensitivity analysis the raw material natural gas shares more than
50 % of production cost and it is very sensitive on project profitability. But
product urea price does not affect project profitability, because production amount
is not changed by the project. Product urea is important for ZIL financial
soundness.
The project continues its negative profit without revamping project based on
estimated urea price of US$/Ton 250. The cashflow also continues its negative
figure. If urea price goes up by US$/Ton 11 or naphtha price comes down by
US$/Ton 21 from base price of US$/Ton 333.43, cashflow turns to positive.
When project is implemented, natural gas price is lower than naphtha one and
improvement of profit is expected with positive cashflow.The project profitability
is very high because of raw material conversion and energy consevation.
Current production cost is very high and is not competitive to international urea
price level. After proejct implementation, the same production cost goes down up
to US$/Ton 193 to 208, which is more than US$/Ton 50 cheaper than current one.
It is understood that conversion from naphtha to natural gas contributes very much
to proejct profitability improvement. There are many projects of LNG terminal
and pipeline to supply natural gas to fertilizer plants, but it would also take much
time to materialize. If raw material of naphtha is not changed to natural gas, ROI
before tax is calculated at 14.77 %.
5. Cost vs Effects and Spread Effect
The quantity of the energy saving over the project life is calculated as 55,705 toe/y.
Intial investment cost for the project is 60,832 MUS$ (6,378 million JPY). Thus,
-7-
the cost versus energy saving of the project is 8.72 toe-y/million JPY.
The reduced quantity of CO? gas as the greenhouse performance gas is estimated
to be 245,139 t-C02/y. Thus, the cost versus greenhouse performance gas
reduction is 38.4t-C02-y/million JPY.
According to the survey in India for this F/S there are 3 fertilizer plants with
similar level of energy consumption as ZIL. Assuming that above all fertilizer
plants could save energy with applying energy saving technologies and feedstock
conversion like the project, total effects of energy saving could be estimated as
169,114 toe/y.
In similar approach to the above, the yearly reduction of C02 gas emission is
expected to be approximately 752,274 t-C02/y.
6. Summary
Fertilizer production in old plants in India became less competitive compared with
international market under the fertilizer subsidy policy by government of India.
The F/S result for without revamp case same as present condition shows minus
cash flow through the total project. The past minus cash flow has been
compensated by subsidy from the government, but the amount of subsidy was
reduced from 2000 and the government decided to phase out the urea subsidy by
April 2006. Therefore old fertilizer plants with naphtha feedstock should be
revamped to change feedstock to natural gas and to reduce energy consumption for
their survival.
The F/S result shows that the project including feedstock change and energy
saving could drastically reduce production cost compared with the without revamp
case. The quantity of C02 reduction including spread effect in India would be
relatively large. Therefore it is understood that urgent implementation of the
project would be necessary.
However, it would take time to decide a detailed government policy, which is
under planning to proceed phasing out the existing subsidy and to complete
decontrol of urea by April 2006. The government recommends to change
-8-
feedstock from naphtha to natural gas in fertilizer plants. So there are many
projects of LNG terminal and pipeline to supply natural gas to fertilizer plants.
But it would also take much time to materialize.
We, Toyo Engineering Corp. will watch and follow the government policy and
investigate projects of LNG terminal and pipeline as well as will support Zuari
Industries Limited (ZIL) as required in every phase of the above development and
implementation of the project.
Following actions are required for further development and implementation of the
project:
Toyo to support ZIL to study and evaluate the result of this F/S based on the
government policy.
Toyo to investigate projects of LNG terminal and pipeline
Both Toyo and ZIL to enter into the preparation for Japanese fund
-9-
CHAPTER 1
PROJECT BACKGROUND
Summary: Based on the present status of politics, economy, society and energy resources of India discussions were made on the project background
__________ such as purpose, needs and effects of the project.____________________
CHAPTER 1 PROJECT BACKGROUND
1.1 Information on India
1.1.1 Political, Economy and Social Status
(1) Political Status
India, a union of states as shown in Fig. 1.1-1 (The map of India), is a Sovereign,
Secular, Democratic Republic with a Parliamentary system of Government. The
Indian polity is governed in terms of the Constitution, which was adopted by the
Constituent Assembly on 26 November 1949 and came into force on 26 January
1950.
The President is the constitutional head of Executive of the Union. Real executive
power vests in a Council of Ministers with the Prime Minister as head. The
Council of Ministers is headed by the Prime Minister to aid and advise the
President who shall, in exercise of his functions, act in accordance with such
advice. The Council of Ministers is collectively responsible to the Lok Sabha, the
House of the People.
The Council of Ministers comprises Cabinet Ministers, Minister of States
(independent charge or otherwise) and Deputy Ministers. Prime Minister
communicates all decisions of the Council of Ministers relating to administration
of affairs of the Union and proposals for legislation to the President. Generally,
each department has an officer designated as secretary to the Government of India
to advise Ministers on policy matters and general administration. The Cabinet
Secretariat has an important coordinating role in decision making at highest level
and operates under direction of Prime Minister
The present Indian Government is a coalition Government headed by Shri. Atal
Bihari Vajpayee as the Prime Miister. The unity of the caolition appears to be
strong and since the period of the Government is five years it can be mentioned
that the present Government is stable and is in a strong position to carry out
economic and social reforms.
-1-1-
The only major International issues facing the Governmant of India are its dispute
with Pakistan over Kashmir and its unwillingness to sign the CTBT
(Comprehensive Nuclear Test Ban Trearty). Economic sanctions were imposed
by the International Community after India conducted nuclear tests in 1998,
however these sanctions have been largely relaxed.
In the states, the Governor, as the representative of the President, is the head of
Executive, but real executive power rests with the Chief Minister who heads the
Council of Ministers. The Council of Ministers of a state is collectively responsible
to the elected legislative assembly of the state.
The Legislative Arm of the Union, called Parliament, consists of the President,
Rajya Sabha and Lok Sabha. All legislation requires consent of both houses of
parliament. However, in case of money bills, the will of the Lok Sabha always
prevails.
A recognised political party has been classified as a National Party or a State Party.
If a political party is recognised in four or more states, it is considered as a
National Party.
The Congress, Bharatiya Janata Party, Janata Dal, Communist Party of India and
Communist Party of India (Marxist) are the prominent National Parties in the
Country. Telugu Desam in Andhra Pradesh, Asom Gana Parishad in Assam,
Jharkhand Mukti Morcha in Bihar, Maharashtrwad Gomantak Party in Goa,
National Conference in Jammu and Kashmir, Muslim League in Kerala, Shiv Sena
in Maharashtra, Akali Dal in Punjab, All-India Anna Dravida Munnetra Kazhagam
and Dravida Munnetra Kazhagam in Tamil Nadu, Bahujan Samaj Party and
Samajwadi Party in Uttar Pradesh and All-India Forward Block in West Bengal are
the prominent state parties.
The Supreme Court is the apex court in the country. The High Court stands at the
head of the state's judicial administration. Each state is divided into judicial
districts presided over by a district and sessions judge, who is the highest judicial
authority in a district. Below him, there are courts of civil jurisdiction, known in
different states as munsifs, sub-judges, civil judges and the like. Similarly, criminal
judiciary comprises chief judicial magistrate and judicial magistrates of first and
second class.
-1-3-
(2) Economy Status
The Indian economy is expected to grow by 5.9 per cent in 1999-2000. More
importantly, an industrial recovery seems finally to be underway from the cyclical
downturn of the previous two years. Growth of GDP from manufacturing will
almost double to 7 per cent in 1999-2000 from 3.6 per cent in 1998-99. The
growth in GDP from the construction sector is expected to accelerate to 9.0 per
cent in 1999-2000 from 5.7 per cent in 1998-99. The performance of
infrastructure sectors improved markedly.
The inflation rate dropped to international levels of 2 to 3 per cent for the first time
in decades. The balance of payments survived the twin shocks of the East-Asian
crisis and the post-Pokhran sanctions with a low current account deficit and
sufficient capital inflows. This was demonstrated by the continuing rise in
foreign exchange reserves by over US $ 2.4 billion during the year until the end of
January, 2000 coupled with a relatively stable exchange rate. Export performance
has improved on par with the better performing emerging economies. The
restoration of confidence in industry has been best reflected in the rise in the stock
market during 1999. Primary issues have increased by almost half during the first
nine months of 1999-2000.
Inflation dropped dramatically in 1999, surprising many observers by remaining at
low levels. As of January 29, 2000, the annual inflation as measured by the
Wholesale Price Index was 2.9 per cent (point to point), down from a peak 8.8 per
cent on September 25, 1998 1}. The strong agricultural growth in 1998-99, the
increasing openness of the economy to manufactured imports along with the fall in
international prices has contributed greatly to this decline.
Exports showed a strong recovery in 1999, growing by 12.9 per cent in April-
Dee ember 1999 in US $ value (Director General of Commercial Intelligence &
Statistics customs data). Software exports, which are not captured in the customs
data, also continued to show vigorous growth of over fifty per cent during April-
September 1999. Despite a 57.8 per cent growth in the US $ value of oil imports
in April-December 1999, overall import growth remained at a manageable 9.0 per
cent. As a result the trade deficit was lower in value (US $) during April-
-1-4-
December 1999 as compared to April-December 1998. Non-oil imports, however,
grew by only 1.1 per cent in this period, as prices of non-fuel primary commodities
were projected to fall in 1999 by over 11 per cent and unit values of manufactures
by about half a per cent.
The current account deficit, which defied gloomy forecasts based on the presumed
after effects of the Asian crisis and the economic sanctions, ended at 1 per cent of
GDP in 1998-99. Both portfolio investment and non-resident deposit inflows have
shown significant improvement. Foreign Direct Investment flows, however,
continue to be lower, and this is a source of serious concern, particularly given the
medium term target of US $ 10 billion of Foreign Direct Investment inflows.
There was a sharp upturn in GDP growth in 1998-99, which reversed the
deceleration in growth seen in 1997-98. GDP (at factor cost) growth accelerated to
6.8 per cent in 1998-99 from 5 per cent in 1997-98 2).
Agriculture
The century ended with the country’s foodgrains output crossing 200 million
tonnes. Foodgrains production in 1998-99 was 203 million tonnes 2). The country
has also emerged as a marginal exporter (2 to 4 million tonnes) of foodgrains.
Private investment in agriculture has been rising over the nineties. From 905.6
million INK in 1993-94 it has risen to 1258.1 million INR by 1998-99 (1993-94
prices). Public investment in agriculture has, however, declined during the same
period so that the growth in total investment is only 21.7 per cent during this
period. There is a need to shift the emphasis of public support for agriculture from
subsidies to investment in rural and agricultural infrastructure and effective
research and extension.
Industry
Industrial growth (as per the Index of Industrial Production) has shown a firm
recovery this year with 6.2 per cent growth in April-December 1999, as compared
to only 3.7 per cent in April-December 1998 1}. The cyclical downturn in
industrial growth, which started in 1996-97, showed some signs of recovery in
-1-5-
1997-98. Manufacturing growth this year at 6.7 per cent during April-December
1999 was 1.7 times the 3.9 per cent witnessed in the corresponding period of last
year. The improved performance of the electricity sector also contributed to the
industrial recovery.
Fertilizer Industry
The Indian fertilizer industry has been supplying a substantial portion of the
growing demand of fertilizers. It had a very humble beginning in 1906, when the
first manufacturing unit was set up in Ranipet near Chennai with a production
capacity of 6,000 tonnes of Single Superphosphate per annum. The Fertilizer &
Chemicals Travancore Ltd. (FACT) at Cochin in Kerala and the Fertilizer
Corporation of India Ltd., Sindri in Bihar, were the first large sized fertilizer plants
to be set up in the forties and fifties with a view to establishing a base for
industrialization and achieving self-sufficiency in foodgrains.
The Green Revolution in the late sixties gave an impetus to the growth of the
fertilizer industry in India. The eighties witnessed a significant addition to the
fertilizer production capacity.
The installed capacity as on February 2000 has reached a level of 11.0 million
tonnes of nitrogen (inclusive of an installed capacity of 20 million tonnes of urea)
and 3.65 million tonnes of phosphate nutrients, making India the third largest
fertilizer producer in the world. The rapid build-up of fertilizer production
capacity in the country has been achieved as a result of a favorable policy
environment and substantial investments made over the years in the public, co
operative and private sectors.
Today, there are 64 large sized fertilizer plants in the country, manufacturing a
wide range of nitrogenous, phosphatic and complex fertilizers. Nine of the units
produce ammonium sulphate as a by-product. Besides, there are about 79 medium
and small-scale single superphosphate units.
The sector-wise installed capacity of Nitrogen and Phosphatic fertilizers is given in
the table below:
-1-6-
Sector-wise Nutrient-wise Installed Capacity of fertilizer as of February 2000
Sector Capacity (million tonnes) % share
N P N P
Public Sector 4.32 0.83 39.02 22.67
Cooperative Sector 2.35 0.52 21.21 14.23
Private Sector 4.40 2.30 39.77 63.10
Total 11.07 3.65 100.00 100.00
Sector-wise Installed Capacity of Urea and its percentage share as of February
2000.
Sector Capacity (million tonnes)
% Share
Public Sector 7.60 37.85
Co-operative Sector 4.67 23.28
Private Sector 7.80 38.87
Total 20.07 100.00
Feedstock Scenario
Of the three main nutrients required for various crops nitrogen, phosphate and
potash, indigenous raw materials are available mainly for nitrogen. The
Government’s policy has aimed at achieving the maximum possible degree of
self-sufficiency in the production of nitrogenous fertilizers based on utilisation of
indigenous feedstock. As of now, the country is self-sufficient to the extent of
about 92.1% in the case of nitrogen. Prior to 1980, nitrogenous fertilizer plants
were based mainly on naphtha as feedstock.
A number of fuel oil based ammonia-urea plants were also set up during 1978 to
-1-7-
1982. In 1980, two coal-based plants were set up for the first time in the country
at Talcher (Orissa) and Ramagundam (Andhra Pradesh). With associated and free
gas becoming available from offshore Bombay High and South Bassein basins, a
number of gas based ammonia-urea plants have been set up since 1985.
In view of the limitations on availability of gas, a number of expansion projects
were taken up in the last few years with naphtha as feedstock with the flexibility
for switching over to gas as and when it is available. Feasibility of a delivery
system of Liquefied Natural Gas (LNG) to meet the demand of fertilizer units and
projects is also being explored.
In the case of phosphates, the paucity of domestic raw material constrains the
attainment of any degree of self-sufficiency. Recognising this, a deliberate
policy-mix has been adopted which involves the modulation of three options: i)
domestic production based on indigenous/imported rock phosphate and imported
sulphur; ii) domestic production based on imported intermediates, viz. ammonia
and phosphoric acid; and iii) import of finished fertilizer, viz. Di-Ammonium
Phosphate (DAP) and very rarely, Mono-Ammonium Phosphate (MAP) and
Nitrogen Phosphate Potash (NPK) complexes.
Roughly 66% of the requirement of phosphatic fertilizers is met through the first
two options. Since indigenous rock phosphate supplies meet only 5-10% of the
total requirement, phosphatic fertilizers produced in the country are essentially
based on imported raw materials and intermediates.
There are no known commercially exploitable reserves of potash in the country and
per force, the entire requirement of potassium fertilizers for direct application as
well as for production of complex fertilizers is met through imports.
In order to bridge the gap between demand and domestic availability, the country
may have to continue to depend on imports to meet the requirement of phosphatic
and potassic fertilizers, due to non-availability of indigenous raw-material.
Fertilizer Prices and Subsidy
The sale prices of controlled fertilizers are fixed by the Government of India
-1-8-
(Department of Agriculture & Cooperation) under the Fertilizer (Control) Order,
1985 issued under the Essential Commodities Act, 1955. At present, only urea,
which is the main nitrogenous fertilizer constituting about 56% of the total
fertilizer consumption in the country, is under statutory price control. The
farmgate price of urea which is fixed at INR 4600 per tonne with effect from
Februrary 2000, excluding local levies, is amongst the lowest in the world and is
heavily subsidised.
The difference between the sale price and the retention price (the cost of
production as assessed by the Government plus reasonable return on net worth) is
paid as subsidy to the individual manufacturing units under the Retention Price-
cum-Subsidy Scheme (RPS). The cost of production of various fertilizer units
differ from unit to unit and even from month to month, depending upon the health
and vintage of the plant, the feedstock used, the levels of capacity utilisation,
energy consumption, distance from the source of feedstock/raw materials, cost of
inputs, etc.
In addition to the retention price subsidy, equated freight subsidy is paid to the
manufacturers of controlled fertilizers to cover the cost of transportation from the
production points to the consumption centres. Since the consumer prices of both
indigenous and imported fertilizers are fixed uniformly, subsidy is also paid on
imported fertilizers in order to bridge the difference between the cost of imports
and the statutorily fixed consumer price.
Concessions/Incentives to Domestic Fertilizer Industry
To encourage investment in the fertilizer sector, the following concessions are
available to the domestic industry:
(a) Concessional customs duty benefit on import of capital goods for setting of new
plants / substantial expansion / renovation / modernisation of existing units.
(b) Deemed export benefits to indigenous supplies of capital goods to
new/revamp ed/retrofit/modernisation of fertilizer projects provided such
supplies are made under the procedure of international competitive bidding and
no price preference is given to indigenous vendors.
-1-9-
Infrastructure
Infrastructure performance has improved substantially during 1999-2000.
Electricity production increased by 7.4 per cent in April-December 1999 compared
to 7 per cent in the corresponding periods of 1998 3). The turn-around was due to
a significant acceleration of the growth rate in thermal power generation to 9.7 per
cent for April-December 1999 from 5.2 per cent in the corresponding period of
1998. The thermal plant load factor has also improved to 65.1 per cent in April-
November 1999 from 61.6 per cent in April-November 1998.
The telecommunications sector continued its fast growth. New telephone
connections provided (Direct Exchange Lines) increased by 33.4 per cent in April-
December 1999 compared to 26.1 per cent in April-December 1998 3). This was
faster than the growth rate of 27.1 per cent in 1997-98. Revenue earning goods
traffic on railways showed a sharp upturn of 8 per cent in April-December, 1999
after having fallen by 2 per cent in 1998-99. Cargo handled at major ports
showed a similar turn around with a growth of 9.2 per cent in April-December,
1999, compared to zero growth in 1998-99.
-1 - 10-
(3) Social Status
India's process of development since 1947 has been accompanied by significant
social changes and an increasing awareness about issues affecting the poor, the
women and the children in India. The Government has made constant attempts to
promote values like democracy, freedom from discrimination, self-reliance and
independence of thought. It has also tried to improve the lot of the poor and weaker
sections of society. Women and children have figured prominently in the
government's agenda of social reforms and initiatives.
Today, India is working towards a society where the poor, marginalised and
underprivileged have equal opportunities in all spheres of life. Partnership and
collective action by the voluntary agencies, government and other like-minded
institutions and individuals have been the key to a meaningful thrust in this
direction.
Welfare State
As a welfare State, India is committed to the welfare and development of its people,
particularly the vulnerable sections like the scheduled castes (SCs), scheduled
tribes (STs), backward classes, minorities and the handicapped. This section of
the society constitutes nearly 85% of the population.
Welfare of the Scheduled Castes, Scheduled Tribes, Backward Classes and
others
Almost a quarter of India's population consists of Schedules Castes and Scheduled
Tribes, who had been grievously neglected for centuries. The government has
taken several steps for their welfare. The representation of the Scheduled Castes
and Scheduled Tribes in all Parliament and State Assemblies is assured.
Under the Special Assistance scheme, nearly 300, 000 families were expected to
benefit during 1994-95. There is a Special Component Plan for the Schedules
Castes. The central government participates in the share capital investment of the
Scheduled Caste Development Corporation, set up in the states. The National SC
and ST Finance and Development Corporation is a 100% government-owned no
-1 -11 -
profit no loss corporation for developing entrepeneurial and other skills of this
section.
Family Welfare Programme
India has 2.4% of the world's land, but supports 16% of the entire global
population. According to the latest (1991) census report, India has a population of
846.30 million. Since the last census (1981), the country's population has
increased by 150 million. Thus the task of eradicating poverty is a daunting one,
indeed.
But the latest census figures have also brought some hope and indicated that efforts
being made in the field of family welfare have not entirely gone waste. For the
first time, the growth rate of population has declined from 2.22% (in 1981) to
2.14%. The Infant Mortality Rate, which was 140 per 1000 live births in 1981,
came down to 80. The death rate declined sharply from 15 per 1000 to 9.6. The
Eighth Plan goal is to achieve a birth rate of 7 per 1000, Infant Moritality Rate of
70 and death rate of 9 per 1000. The life expectancy is expected to hit 64 from 58
years at present.
-1 -12 -
1.1.2 Energy Strategy
(1) Crude Oil
Crude oil production in the country during 1998-99 was 32.7 million tonnes against a
target of 34.0 million tonnes. The production target for the year 1999- 2000 is 33.0
million tonnes.
Several measures were taken by the Government to intensify exploration and enhance
hydrocarbon reserves. These included development of new fields, additional
development of existing fields, implementation of Enhanced Oil Recovery Schemes,
recourse to specialised technology, enlisting the services of international experts and
encouraging participation of private and joint venture companies in the exploration
programme.
Under the New Exploration Licensing Policy (NELP), 48 blocks were offered. By the
bid closing date of August. 1999, a total of 45 bids for 27 blocks were received from
both foreign and Indian companies including public sector undertakings. Out of these,
25 blocks have been awarded. Bids for 2 blocks were rejected, as they did not satisfy
the technical requirements.
The import of crude oil between April - November, 1999 was 31.5 million tonnes
valued at 196 billion INR and of other petroleum products 9.5 million tonnes valued at
71.95 billion INR. Exports upto November, 1999 were of 0.531 million tonnes
valued at 3.72 billion INR.
Refining Capacity and Throughput
The refining capacity of 69.14 million tonnes per annum as on January 1999 has
increased to 109.0 million tonnes per annum as on January 1, 2000, making the
country almost self-sufficient in the refining sector.
There are 17 refineries in the country, of which 7 are owned by Indian Oil Corporation
Limited (IOCL), two each by Hindustan Petroleum Corporation Limited (HPCL) and
Madras Refineries Limited (MRL), one each by Bharat Petroleum Corporation Limited
(BPCL), Cochin Refineries Limited (CRL), Bongaigoan Refinery & Petrochemicals
Limited (BRPL), Numaligarh Refinereis Limited (NRL), Mangalore Refinery &
-1 -13 -
Petrochemicals Limited (MRPL) and Reliance Petroleum Limited (RPL).
Keeping in view the need of enhancing the refining capacity to meet the growing
demand of petroleum products, a number of grass root refineries as well as expansion
of existing refineries have been commissioned and some are under various stages of
implementation. As per the current outlook, the refining capacity is expected to go
upto 129 million tonnes per annum by the end of IX th Plan as against the estimated
demand of products of 110 million tonnes.
In the year 1998-99, about 39.8 million tonnes of crude oil was imported valued at
148.8 billion INR. Import of crude upto November 1999, was 31.5 million tonnes
valued at 196.1 billion INR.
During 1998-99, 18.78 million tonnes of products was imported at a cost of 98.4
billion INR. During the current year upto November, 1999 the import of petroleum
products was 9.51 million tonnes valued at 71.95 billion INR.
During 1998-99, the export of petroleum products (including supplies to Nepal) was
1.40 million tonnes for a value of 8.56 billion INR. The export of petroleum products
during April- November, 1999 was 0.53 million tonnes valued at 3.72 billion INR.
Crude Oil and Product Pricing
The administered pricing mechanism (APM) which was in vogue in the petroleum
sector since the mid 70's provided returns to the oil companies based on a
predetermined percentage. While the administered pricing mechanism (APM)
ensured price stability, it did not encourage cost minimisation, efficient use of capital,
customer friendly competitive environment etc. Subsidies/cross subsidies resulted in
wide distortions in consumer prices resulting in inefficient usage of scarce products.
Further, administered pricing mechanism (APM) was less transparent and therefore
investors were reluctant to commit large funds in petroleum sector. Infrequent revision
in product prices in line with international developments resulted in accumulation of a
large deficit in the Oil Pool Account in the last few years. Hence, it was considered
necessary to move towards a market driven price mechanism in a phased manner.
The process of deregulation and liberalisation will be continued during the transition
-1 -14 -
period in further rationalisation in tariffs to provide effective tariff protection to the
refineries, reduction in transport subsidies/subsidies for kerosene and LPG (Domestic)
in a phased manner and the liberalisation of the EXIM Policy to reflect the process of
reforms.
(2) Natural Gas
Natural gas has been utilised in Assam & Gujarat since the sixties. There was a
major increase in the production & utilisation of natural gas in the late seventies with
the development of the Bombay High fields and again in the late eighties when the
South Bassein field in the Western Offshore was brought to production. The
production of natural gas during 1998-99 was around 75 mmSm3/D. Sale of natural
gas during 1998-99 was around 60 mmSm3/D out of which GAIL sold about 57.4
mmSm3/D.
Most of the production of gas comes from the Western offshore area. Assam, Andhra
Pradesh and Gujarat are other major producers of gas. Smaller quantities of gas are
produced in Tripura, Tamil Nadu and Rajasthan. 60% of the natural gas is produced
along with crude oil as associated gas. The rest is produced as free gas. The South
Bassein and Tapti fields in the Western Offshore and the gas fields in Tripura and
Andhra Pradesh(K.G. Basin) are the main producers of free gas.
The gas produced in the western offshore fields is brought to Uran in Maharashtra and
partly in Gujarat. The gas brought to Uran is utilised in and around Mumbai. The
gas brought to Hazira is sour gas which has to be sweetened by removing the sulphur
present in the gas. After sweetening, the gas is partly utilised at Hazira and the rest is
fed into the Hazira-Bijaipur-Jagdhishpur(HBJ) pipeline which passes through Gujarat,
MadhyaPradesh, Rajasthan, U P., Delhi and Haryana. The gas produced in Gujarat,
Assam, etc; is utilised within the respective states.
There have been demands from the Southern states for a Southern Grid to carry gas
from the Western offshore gas fields and other sources to Southern India. The
concept of Southern Grid has been accepted in principle. A pre-feasibility study to
estimate the potential demand has been completed. While the proposals for import of
gas through pipeline from Oman and Iran have not met with any progress for technical
& geo-political reasons, it was considered that importing Liquefied Natural Gas (LNG)
-1 -15 -
for Southern India as well as other coastal locations would be viable alternative.
Import of Natural Gas
The production of natural gas in the country is expected to level-off at around 85
mmSm3/D. The demand of gas registered with GAIL upto 1992 itself is of the order
of 260 mmSm3/D. Projections of gas demand made by a number of agencies indicate
a wide and growing gap between demand & gas supply. To meet this gap, the
Government have taken steps for import of natural gas from the Middle-East. An
Agreement of Principal terms was signed with Oman in September’1994.
The project envisaged import of 56.6 mmSm3/D of gas by the end of decade. A
Memorandum of Understanding (MOU) was also signed with Iran in July 1993
followed by another MOU in November’1993. However, due to technical & geo
political reasons, these projects have not materialised. Feasibility of importing gas
from Bangladesh and Myanmar to the eastern/Southern parts of the country are also
being explored.
The feasibility of importing LNG from sources such as Middle-East, south East Asia,
Australia, etc; is being pursued to meet the additional demand for gas. A joint
venture company M/s. Petronet LNG Ltd. has been formed consisting of GAIL,
ONGCL, IOCL and BPCL with equity participation of 50%. NTPC is also to join
this JV Company. M/s. Petronet LNG Ltd. has identified two locations namely, Dahej
(Gujarat) & Cochin (Kerala) for setting up LNG terminals. They have signed a Long
Term LNG Sale Purchase Agreement with M/s. Rasgas of Qatar. Work on setting up
of these terminals is under progress.
Gas Pricing
In 1990, the Government appointed the Kelkar Committee to recommend revisions
required in gas prices. After considering the recommendations of this committee, the
price of gas was revised January 1992 as follows:
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(Unit : MCM means thousand cubic meter)
Offshore gas at landfall point or onshore gas INR 1500/M CM
Transportation charges for sold along HBJ Pipeline INR 850/MCM
Gas Sold in North Eastern States INR 1000/M CM(with a concession of INR 400/MCM on case to case basis)
The aforesaid prices of natural gas were lower than the price of alternative fuels such
is fuel oil, naphtha etc. It was felt that gas prices needed to be increased to meet the
rising costs of production and transportation. A Committee was constituted under the
chairmanship of Shri T.L.Shankar, Principal, Administrative Staff College of India,
Hyderabad to recommend the levels of gas prices and the principles that should
determine gas prices.
In pursuance of the recommendations of the committee, it has been decided by the
Government that from January1997 and upto March 2000, the consumer price of gas at
landfall points would be linked to the price of a basket of Low sulfur/High sulfur fuel
oils as shown in the table below:
Year General Price Concessional Price for the North Eastern States
1997-98 55% 30%
1998-99 65% 40%
1999-2000 75% 45%
The prices would be reviewed before March 2000 for a further period.
The price would be determined and notified by GAIL with the approval of the
Ministry for every quarter depending upon the average price of the basket of fuel oils
based on figures obtained from Platts Oil Gram for the previous quarter. The general
price would vary between the floor price of INR 2150/MCM and the ceiling price of
INR 2850/M CM and the concessional price for the North Eastern States would have a
floor price of INR 1200/MCM and a ceiling of INR 1700/M CM. A discount of INR
300/MCM would also be available to the existing consumers in the North East on a
case to case basis and the concessional price and the discount of INR 300/MCM would
-1 -17 -
be available on a case to case basis to the new units in the North Eastern States set up
during 1997-2002 for a period of five years.
The prices of natural gas as approved by the Ministry of Petroleum and Natural Gas
for the quarter ending October- December 1999 are as follows:
Other than HBJ Pipeline and North-Eastern States:
Producer Price (at 10,000 Kcal/Sm3): INR 2513/MCM
General Consumer Price(at 10,000 kcal/Sm3): INR 2850/M CM
HBJ Pipeline System:
Producer Price (at 10,000 Kcal/Sm3): INR 2513/MCM
General Consumer Price(at 10,000 kcal/Sm3) : INR 2850/M CM
HBJ Transportation Charges(at 8500 Kcal/MCM) : INR 1150/M CM
North Eastern States:
Producer Price (at 10,000 Kcal/Sm3) : INR 1700/M CM
General Consumer Price (at 10,000 kcal/Sm3): INR 1700/M CM
The above prices are exclusive of transportation/service charges, royalty, taxes, duties
and other statutory levies on production, transportation and sale of natural gas.
Major Projects recently implemented
The following projects relating to production/transportation/utilisation of natural gas
have recently been implemented:
The Gas Flaring Reduction Project
This project has been implemented by ONGC by setting up transportation and
compression facilities in the Western Offshore. The project comprises the NQP and
SHG processing platforms in the Bombay High, the ICP-Heera and the Second
Bassein - Hazira trunk pipeline and the expansion of the Hazira gas terminal. NQP
and SHG platforms, the ICP - Heera pipeline, the second Bassein-Hazira trunk
-1-18-
pipeline have been commissioned. The expansion of the Hazira gas terminal was
also completed in 1997-98. Both the World Bank and the Asian Development Bank
(ADB) have participated in the funding of this project costing around 75.0 billion INR.
The HBJ Upgradation Project
This project was approved by the Government in March, 1994 at an estimated cost of
23.76 billion INR. The capacity of the HBJ pipeline which was 18.2 mmSm3/D has
been upgraded to 33.4 mmSm3/D by adding extra compression facilities and a new 36"
loop line from Bijaipur to Dadri at a cost of 237.6 million INR. The pipeline was
commissioned in March,'97 and the compressor stations during 1997-98.
LNG Projects at Dahej and Kochi
The projects for import of liquefied natural gas at Dahej and Kochi are being
implemented by Petronet LNG Limited. This company was incorporated in April,
1998 and is setting up LNG Terminals at Dahej (5 million tonnes per annum) and at
Kochi (2.5 million tonnes per annum). They have recently signed the sale purchase
agreement for LNG supplies with M/S Rasgas-Mobil of Qatar and work on setting up
of the terminals is progressing. The project at Dahej is scheduled to be completed in
2003 and that at Kochi by 2005.
(3) Coal
The coal reserves of India, upto the depth of 1200m, have been estimated by the
Geological Survey of India as 211,600 million tonnes as on January 2000
Currently, lignite reserves in the country have been estimated at around 30,300
million tonnes, most of which, occur in Tamil Nadu. Other states where lignite
deposits have been located are Rajasthan, Gujrat, Kerala, Jammu and Kashmir and
Union Territory of Pondicherry.
Coal Production
Coal production achieved during the year 1999-2000 (upto December, 99) has been
208 million tonnes as compared to the production of 206 million tonnes achieved
during same period of the previous year i.e. 1998-99( given below).
-1-19-
About 86% of the total coal production in the country comes from the collieries of
Coal India Ltd. (CIL) is also the biggest supplier of coal in the country.
Company-wise details are given below:
(In million tonnes)
Company Target(Apr.-Dec. 99)
Actual production (Apr-Dee. 99)
Actual production (Apr-Dee. 98)
CIL 162.19 160.12 183.45
SCCL 18.65 15.55 18.31
TOTAL 185.21 179.64 206.39
Demand and Supply
During the year 1999-2000 (April-December), CIL and
following quantities of coal to various consumers:
Coal India Ltd (CIL) 1999-2000 (April-December)
SCCL supplied the
(million tonnes)
Target Actual Offtake Supply %
Power 136.736 140.999 103
Steel 14.122 10.946 78
Cement 4.363 4.807 110
Fertilizer 786 2.387 0. 3
Others 31.511 30.664 97
Total 189.518 189.803 100
-1 - 20 -
Singareni Collieries Company Ltd(SCCL) 1999-2000 (April-December)
(million tonnes)
SECTOR Target Acrual Offtake Supply %
Power 16.76 17.90 106.8
Cement 2.32 2.32 100.0
Fertiliser 0.44 - -100.0
Others 2.68 1.91 71.3
Total 22.46 22.35 99.5
During 1999-2000 offtake of Coal from SCCL has been 22.35 million tonnes
against a demand/linkage of 22.46 million tonnes. This reflects a demand
satisfaction of 99.5%.
Price of Coal
The latest average price of CIL coals as fixed on May 1999 is INR 596 per tonne
whereas the latest average base price of SCCL coal as fixed on Septemebr 1999 is
INR 775.62 per tonne.
- 1 - 21 -
1.1.3 Needs of Clean Development Mechanism (CDM)
Population of India almost reaches one billion and is estimated to become above
China in near future. Therefore food, fertilizer, energy, social overhead capital
etc. should be increased. Most of fertilizers necessary for agricultural product have
been produced in India to secure domestic supply of food. The government of
India gives fertilizer sector subsidy to fix sales price of fertilizer to secure
domestic production.
Under such subsidy policy old fertilizer plants with less efficiency are still
operated and drastic improvement of fertilizer plants with feedstock of heavy
hydrocarbons such as coal, heavy oil, naphtha have been suspended. Therefore
production of fertilizer in India became less competitive compared with
international market. In order to improve such situation old fertilizer plants with
naphtha feedstock should be revamped to change feedstock to natural gas and to
reduce energy consumption, which are in compliance with the guideline of long
term policy on fertilizer sector being proposed by the government of India.
C02 emission 4) in India was approx. 893 million tonnes as C02 (total emissions
from the consumption and flaring of fossil fuels in 1999), which was fifth position
in the world following U.S.A, China, Russia and Japan. Breakdown of total
emissions in India was 269 million tons from petroleum (30 %), 573 million tons
from coal (64 %), 51 million tons from natural gas (6 %) respectively.
GDP of India reached approx. 17,700 billion INR (approx. 380 billion US$) in
1999-00. GDP per capita was approx. 18,200 INR (approx. 390 US$). India is
still one of under-developing countries from view points of social overhead capital
and technical capacity, thus it is required as well as expected to apply CDM which
will be collaboratively implemented between developed and under-developing
countries.
India can not only utilize modern technologies from Japanese corporations, but
also contribute to the reduction of greenhouse performance gas, by using Japanese
fund.
Judging from the above backgrounds, it can be seen that the application of CDM is
highly needed for India in view points of introduction of foreign technologies and
reduction of greenhouse performance gas.
- 1 - 22 -
1.2 Necessity of Technology Introduction for Energy Saving
Ammonia production from naphtha feedstock is approx. 37 % in overall domestic
ammonia production including from natural gas, heavy oil and coal. Most of
naphtha feedstock ammonia plants are old and have less energy efficiency. These
plants have been revamped for capacity increase after commissioning under the
subsidy policy of the government of India.
Ammonia production capacity by feedstock in India
Naturalgas
Naphtha Fuel oil Coal Total
Daily 21,014 16,752 5,235 1,800 44,801capacity tons
Ratio 46.9 37.4 11.7 4.0 100 %
However the government of India recently proposed the guideline of fertilizer
subsidy policy with 3 steps reducing amount of subsidy in order to minimize
financial deficit due to increase of subsidy and to recover competitiveness of
fertilizer production cost considering the affiliation to WTO.
The fertilizer companies based on naphtha feedstock will suffer due to not only
reduction of subsidy, but also recent high naphtha price. Therefore old fertilizer
plants with naphtha feedstock should be revamped to change feedstock to natural
gas and to reduce energy for their survival.
The necessity of technology introduction for energy saving is very high in India.
-1 - 23 -
1.3 Purpose, Need and Effect of the Project
1.3.1 Purpose of the Project
The major purposes of the project are to reduce emission of the greenhouse
performance gasses as well as to reduce fertilizer production cost by feedstock
change and energy saving in a typical fertilizer plant in India. At the same time,
it is expected to spread applied technologies in similar fertilizer plants. It is
aimed to secure self-sufficiency in the production of food and to contribute to the
development of agricultural industry and fertilizer sector in India. It is also aimed
to contribute the successive involvement of Japanese corporations in Indian
projects.
This project could have a remarkable significance because it can contribute to
arresting global warming as well as to development of industry and economy in
India with involvement of Japanese corporations and introduction of Japan’s
technologies.
1.3.2 Need of the Project
This project was originally planned based on the strong request from Zuari
Industries Limited (ZIL) in India in order to survive in fertilizer business against
high feedstock price and reduction of fertilizer subsidy. The feedstock change
and energy saving incorporated in this project is in line with the expected long
term policy on the fertilizer sector by the government of India. Therefore this
project could be highly needed for India.
Since infrastructure such as railway and road are under developed, mass
transportation of fertilizer product is not easy in India. Fertilizers produced in
ZIL are distributed not only in Goa, but also in the neighboring states, so ZIL have
an important role as a supply center of fertilizers in south west coast in India.
This project is essential for local agricultural industry.
The energy saving of the project could reduce expensive naphtha used for
feedstock and fuel, thus have a large impact on production cost reduction and
-1-24-
reduction of greenhouse performance gas (CO?) emission.
The feedstock change from naphtha to natural gas of the project could reduce
energy consumption and CO? emission. Natural gas supply to ZIL through pipe
line, however, might take more time. There are many under consideration
/implementation projects of LNG terminal and pipe lines in India because the
domestic reserve of natural gas is limited. Some projects have already been started
and under implementation. The existing pipe line network (HBJ) is located in
northern part of India and the LNG pipe line projects are planned for southern part
of India connecting ZIL with LNG terminal, but it might take more time.
1.3.3 Effect of the Project
In case that the project would be materialized, the following effects are expected
to;
- reduce the greenhouse performance gas (approx. 0.25 million tonnes/year as
CO,)
- spread applied technology in India
- contribute to the development of industry and economy in India,
- allow Japanese corporations to participate successively in India projects, and
- secure the C02 emission right of Japan
-1-25-
CHAPTER 2
PROJECT PLANNING
Summary: Surveys were made on Zuari Industries Limited and its existing facilities, in order to develop the project planning. Reflecting the survey results, project scope and scheme of revamp, scope of supply, project execution, project schedule, estimation of plant cost, financing plan and issues for
CDM implementation were examined.
CHAPTER 2 PROJECT PLANNING
2.1 Project Plan
2.1.1 Site Information
(1) Location and Topography
1) Site Name Zuarinagar
- City's or Region's Name Goa
- Country's Name India
2) Longitude and Latitude
- Longitude 74°15' East
- Latitude 15°25' North
3) Height above the Sea Level
- Above Sea Level 60 m
4) Approximate Location
- Distance
- Approx. Location from the River
- Approx. Location from the Sea
5) Topography
- Flat
- Other Description
Climate Tropical climate with rainy and
dry season
6) Topographical Survey Report
Not available
7) Access to the Site
- Road
30 km from the Panaji city
“Zuari River", 5 km East
on the coast of Arabian Sea
-2-1-
(2) Geology
1) Geological Survey Data
Not available
2) Soil Investigation Report
Not available
3) Soil Data
Not available
(3) Meteorological Conditions
1) Atmosphere Temperature (1951-1980 average)
X\Month 1 2 3 4 5 6 7 8 9 10 11 12
Temp.^cN^ Jan. Feb. Mar. Apr. May June July Aug. Sep. Oct. Nov. Dec.
Ave. Temp. (Max) 30.8 30.5 31.3 32.3 32.2 29.9 28.6 28.5 29.2 31.1 32.4 32.1
Ave. Temp. (Min) 21.4 22.1 24.4 26.3 26.8 24.7 24.0 24.0 24.0 24.4 23.4 22.2
Maximum Temperature Used in the design 36 °C
Minimum Temperature Used in the design 17 °C
2) Humidity (1951-1980 average)
Mean Monthly and Annual Relative Air Humidity (%)
1 2 3 4 5 6 7 8 9 10 11 12 Year
Jan. Feb. Mar. Apr. May June July Aug. Sep. Oct. Nov. Dec.
63.5 67.5 71.0 71.0 72.5 84.0 87.5 86.5 84.5 78.5 64.5 61.0 74.5
-2-2-
3) Wind (1951-1980 average)
Month
WinoX
Directions,
1 2 3 4 5 6 7 8 9 10 11 12
Jan. Feb. Mar. Apr. May June July Aug. Sep. Oct. Nov. Dec.
Basic WindDirection
EastNorth
West
North
WestWest
North
West
South
WestWest West West West East East
Max. WindVelocity
10.5 11.8 12.2 13.1 14.9 18.4 21.7 18.3 11.5 9.2 9.1 9.3
Maximum Wind Velocity Specified in the Design 61 km/h
4) Rainfall (1951-1980 average)
Monthly and Yearly Rainfall (mm)
\Month 1 2 3 4 5 6 7 8 9 10 11 12 Year
Falls Jan. Feb. Mar. Apr. May June July Aug. Sep. Oct. Nov. Dec.
Monthly & Yearly
0.2 0.0 0.2 9.0 75.7 782.1 874.1 444.0 237.5 113.3 28.6 14.2 2578.9
-2-3-
2.1.2 Project Concept
Zuari Industries Limited (ZIL) in Goa, India produces ammonia with feedstock of
naphtha and also produces urea from ammonia and C02 produced in the ammonia
plant. The energy consumption of these plants are considerably large compared with
latest modern plants and the ammonia plant uses expensive naphtha as feedstock and
fuel.
The Project objectives are to reduce fertilizer production cost and to decrease
discharges of C02 gas into the atmosphere by feedstock change and energy saving.
In ammonia process a large quantity of energy is consumed. Reforming of
naphtha feedstock consumes a large quantity of steam and COz removal consumes
heat to regenerate C02. High pressure compressor also consumes a large quantity
of steam. Energy saving technologies are applied in the project to reduce energy
required in C02 removal, high pressure ammonia synthesis and steam turbines.
The major applied technologies are listed below.
1) aMDEA process for C02 removal
2) KAAP converter installed in ammonia synthesis
3) High pressure condensate stripper
4) Modification of compressors and turbines
The following rotor will be replaced to new ones with high efficiency.
- Synthesis gas compressor low pressure and high pressure
- Turbine of the synthesis gas compressor
- Ammonia compressor
Urea synthesis reaction occurs at high temperature and high pressure and consumes
a large quantity of power and steam. The total steam consumption has been
reduced by the improvement of process. TEC's ACES 21 process featuring
improvement of reaction efficiency and effective recovery of heat is applied to the
existing urea plant to reduce energy effectively and economically. Turbine of C02
booster compressor of urea plant will be replaced.
Energy saving is also achieved by feedstock conversion from naphtha to natural gas
in the ammonia plant.
-2-4-
Project scope is revamp of existing ammonia and urea plants. Scope of works for
the project includes design, procurement, construction and supervising during
commissioning for the revamp.
In addition, financing of the fund required for the revamp, environment impact
assessment, transportation and custom clearance of goods and materials, and
statutory approval are also included in the project scope.
2.1.3 Greenhouse Performance Gas to be examined
The existing ammonia plant uses naphtha for feedstock and fuel. The urea plant
uses ammonia and C02 produced in the ammonia plant as feedstock and steam as
energy input. In the ammonia plant feedstock naphtha is reformed and the
reformed gas is purified to produce synthesis gas for ammonia production. C02 is
produced after purification of synthesis gas. If natural gas is used for feedstock,
produced C02 will be decreased compared with naphtha. The produced C02 will be
used as feedstock of urea, the balanced C02 will be vented to the atmosphere.
Required energy in ammonia and urea plants is produced by combustion of fuel and
C02 is vented to the atmosphere. Nitrogen oxides are also produced and vented, but
the quantity is very small.
The project plan in this feasibility study focuses on the reduction of C02 as the
greenhouse performance gas.
-2-5-
2.2 Outline of Zuari Industries Limited (ZIL)
Zuari Industries Limited (ZIL) was established in 1967 as a private fertilizer
company jointly sponsored by the house of Birlas and U.S. Steel Corporation. In
1969 Toyo Engineering Corp. (TEC) in Japan was awarded to construct ammonia
660 t/d, urea 1,140 t/d and NPK 535 t/d plants in Goa.
The design, erection and construction of these plants were done by TEC using its
own technologies and these plants started production in 1973. These plants were
ones of the largest, fully integrated, ammonia and urea complex in India and Goa's
first large industrial undertaking.
ZIL expanded its fertilizer plants by adding DAP (in 1984) in Goa. The fertilizers
produced are supplied not only to Goa, but also to Andhra Pradesh, Karnataka and
Maharashtra. ZIL fertilizer division has the following plants in Goa.
- Ammonia 220,000 t/y (as original design)
- Urea 376,000 t/y (as original design)
- NPK 330,000 t/y
- DAP 330,000 t/y
- Power generation 7.5 MW (for internal use)
ZIL has other divisions in addition to fertilizer division in Goa. Other divisions,
related subsidiaries and Joint ventures are as follows.
Other divisions
- Cement, based in Yarraguntla, Andhra Pradesh
- Furniture, based in Chennai, Tamilnadu
Subsidiaries
- Birla Home Finance Ltd.
- Zuari Investments Limited
Joint ventures
- Zuari Seeds limited
- Simon India Limited
Chambal Fertilizers and Chemicals Limited (CFCL) promoted by ZIL was set up as
-2-6-
large fertilizer plants at Gadepan, Kota, Rajasthan in 1985. CFCL started
production of ammonia 450,000 t/y and urea 750,000 t/y in 1993. TEC was
awarded CFCL's expansion project with same size of ammonia and urea which
were started in 1999.
2.2.1 Intention of Zuari Industries Limited (ZIL)
ZIL requested TEC, which constructed his ammonia and urea plants, to execute of
feasibility study of the feedstock change and energy saving of his ammonia and
urea plants in December 1999. TEC made a preliminary plant survey and clarified
ZIL's request.
The fertilizer production cost of ZIL was relatively high due to expensive naphtha
used for feedstock and fuel. ZIL needed improvement of production cost in order
to survive in fertilizer business against high feedstock price and reduction of
fertilizer subsidy. ZIL's top management directly requested TEC to study F/S.
ZIL has a keen interest in the result of study and after confirming economical
feasibility in detail and the fertilizer policy of the government ZIL could have an
intention to start the project.
The first plant visit for this feasibility study in September 2000 was featured on
ZIL’s house magazine. Not only top management, but also all memebers of ZIL
have committment to this project.
-2-7-
2.2.2 Conditions and Status of Related Infrastructure and Facilities
2.2.2.1 Ammonia Plant
This ammonia plant was constructed by Toyo Engineering Corporation based on its
Steam Reforming Process for producing ammonia starting with naphtha as feed and
production was started in 1973. The original design of ammonia production
capacity was 660 metric tonnes per stream day (hereinafter referred to "MTPD").
This ammonia plant has been modified by ZIL to mainly increase the production
capacity. Major modification item is as listed below.
- Additional Purge Gas Recovery Unit, installed in 1980 (production was increased
by 90 t/d)
- internal of Ammonia Converter, modified in 1990
- Reformer tube, replaced in 1994
- Additional Air compressor, heat exchanger and etc. installed
- Additional Heat exchangers, installed for energy saving
The maximum ammonia production rate had reached 970 MTPD in 1999.
However, owing to the feedstock price and Indian government guide, the ammonia
production has been limited to 750 MTPD and the energy consumption has been
about 10.1 Gcal per ton of ammonia in 2000. This production rate and the energy
consumption were chosen as the basis of this feasibility study.
Under normal operating conditions, liquid ammonia product is delivered at 10°C
and 18 kg/cm2G directly as feed to the Urea Plant. If the urea plant is not operating,
total ammonia product will be delivered as liquid of 4°C to spherical storage tanks.
Adequate carbon dioxide (C02) to manufacture urea is produced and sent to the
Urea Plants.
An Ammonia Simplified Flow Diagram (Existing) is shown in Fig. 2.2-1.
-2-8-
In)
<o
1ST REFORMER 2ND REFORMER SHIFT CONVERTERS
COMB. CHAMBER
AIR COMPRESSOR
STEAMFEEDNAPHTHA—►
STEAM CO, REGENERATORMETHANATOR CO,ABSORBER ^
CO, GAS TO UREA
PROCESSS CONDENSATESYN. GAS COMPRESSOR
AMMONIACONVERTERS
AMMONIA COMPRESSORPRODUCT LIQUID AMMONIA
Fig.2.2-1 Ammonia Simplified Flow Diagram (Existing)
The Process Unit is grouped into the following sections for the explanation.
- Hydrotreating Section
- Feedstock Treating Section
- Reforming Section
Shift Conversion Section
Carbon Dioxide Removal Section
- Methanation Section
Synthesis Section
Refrigeration Section
- Ammonia Recovery Unit and Purge Gas Recovery Unit
- Process Condensate Stripping Section
Steam System
- Other Facilities
1) Hydrotreating Section
Sulfur contained in naphtha charged to steam reforming units acts as a poison
to the reforming catalysts, and must be removed by pretreatment.
Accordingly, a two-step desulfurization process is used, consisting of a
hydrotreater-stripper (HDS) operation followed by an "open sandwich"
catalytic desulfurization final cleanup. The latter will be included in the next
section.
In the Hydrotreater Reactor (A-DC001), the liquid feed, accompanied by a
hydrogen-rich recycle gas, is passed over a Cobalt-Molybdenum catalyst bed
and the sulfur compounds are catalytically hydrogenated to H2S. After
stripping out the H2S, it is expected that the sulfur content in the liquid feed is
reduced to less than 5 ppm by weight. In the second desulfurization step in
the next section, the remaining non-reactive sulfur compounds, not removed
in the first step, are again hydrogenated over a Cobalt-Molybdenum catalyst
bed to H2S, and removed by reacting with zinc oxide in a final bed, A-DA102.
The sulfur content is reduced to less than 0.1 ppm by weight in the A-DA102.
The activity to the primary reformer catalyst is related to the sulfur content in
the feed, and it is anticipated that by reducing the sulfur to 0.1 ppm in the
- 2 -10 -
liquid, full primary reformer catalyst activity and life are assured.
The hydrotreater unit has been designed to process sufficient liquid feed to
supply the ammonia plant reformer.
The liquid feed is pumped from storage and mixed with recycle gas from the
recycle compressor, the hydrogen rich makeup gas which provides the
hydrogen atmosphere over the hydrotreater catalyst. The mixture is first
preheated by passing through a No.l Hydrotreater Reactor Feed/Effluent Heat
Exchanger (A-EA002) and then heated to the hydrotreater reaction
temperature by a Raw Naphtha Heater (A-BA001). A stream of ammonia
synthesis gas taken from the feed to the ammonia synthesis loop is used as the
hydrogen rich makeup gas, and added at the discharge of the Recycle Gas
Compressor (A-GB001), to offset the purge gas and to maintain H2S and inerts
concentration in the recycle gas to a permissible operating level.
The completely vaporized mixture next passes through the Hydrotreater
Reactor (A-DC001) where the hydrogenation of sulfur compounds proceeds.
The Hydrotreater Reactor contains Cobalt-Molybdenum catalyst. In the
presence of the Co-Mo catalyst, organic sulfur compounds are hydrogenated
to H2S. On leaving the reactor, the effluent is cooled by heat exchangers
with hydrotreater feed and cooling water. In cooling, liquid is condensed
and then separated from the recycle gas. The liquid then flows to the
stripper. The large portion of vapor separated from the liquid is recycled to
the hydrotreater inlet via the recycle compressor. A small portion of the
vapor is purged to Primary Reformer as fuel gas.
The liquid flows to the H2S Stripper (A-DA001), where the dissolved H2S is
stripped with a small amount of light ends and passed off overhead. The
stripping heat is supplied at the bottom of the stripper by the H2S Stripper
Reboiler (A-EA001). The overhead vapor combined with the purge gas is
sent to Primary Reformer as fuel gas. The stripper tower contains trays.
The hot bottom product from the stripper, contains less than 5 ppm by weight
of sulfur.
-2-11-
Auxiliary facilities are provided for various operations involved in start-up,
and shut-down. Piping is provided for circulating inert gas through both
desulfurizers for heating up the catalysts prior to introducing naphtha. By
using cracked ammonia as a hydrogen source, raw naphtha may be processed
in normal fashion and then routed to naphtha storage through the Treated
Naphtha Cooler (A-EA007), provided for this purpose. These facilities can
be also utilized to handle emergency dumping of the desulfurizing systems
when forward flow to the primary reformer must be discontinued. De-coking
facility is also provided for Raw Naphtha Heater (A-BA001).
2) Feedstock Treating Section
The desulfurized naphtha from the bottom of H2S stripper, is pumped by
Naphtha Feedstock Pump (T-GA103) to the Feedstock Preheater (A-BA102)
after mixing with recycle H2.
The Feedstock Preheater (A-BA102) is designed to achieve required
temperature of desulfurization. After preheating, the feedstock flows to
Hydrotreater catalyst to decompose organic sulfur to H2S on Cobalt-
Molybdenum catalyst as the first step. The following Desulfurizer catalyst
removes all sulfur down to 0.1 ppm as total sulfur by the reaction with packed
Zinc Oxide forming Zinc Sulfide as the second step. The volume of Zinc
Oxide is designed to last required years at the design sulfur load.
3) Reforming Section
Desulfurized naphtha from Desulfurizer is mixed with superheated steam in an
amount equivalent to a steam-organic carbon ratio of 3.3 to 1 for naphtha
feedstock. The gas-steam mixture is then preheated and distributed to
catalyst tubes suspended in the radiant section of 1st Reformer (A-BA101).
It passes down in contact with nickel reforming catalyst inside the tubes.
The Primary Reformer operates with down-firing of fuel naphtha between the
rows of tubes to raise the process gas temperature to required temperature at
the outlet of the catalyst tubes which will be controlled by total fuel flow to
- 2 -12 -
the arch burners. Under this condition, the gas will contain about 10 vol.%
dry unconverted methane. The pressure at the outlet of the catalyst tubes is
about 30 kg/cm2G.
The 1st Reformer is designed to attain good efficiency by recovering heat in
the convection section from the flue gas.
The convection heat is used for the following services:
(a) To preheat the steam feed
(b) To preheat the steam-air mixture to the 2nd Reformer
(c) To superheat high pressure steam
(d) To preheat combustion air
For firing the reformer furnace, the design is based on utilization of naphtha.
Water-washed purge and flash gas from the ammonia synthesis section is
utilized as fuel for Combustion Chamber of which flue gas duct is combined
with the dact of the reformer. Combustion Chamber is 99 Kg/cnfG steam
generator.
Partially reformed gas flows from the outlet of the Reformer to the refractory
lined 2nd Reformer (A-DC101) is mixed with an amount of air preheated in
the 1st Reformer convection section, fixed by the nitrogen requirement for the
ammonia synthesis. The gas, steam and air pass downward through a bed of
nickel catalyst. The heat liberated by the combustion of the partially
reformed gas elevated the temperature at the outlet to about 1000°C and
supplies the energy to complete the reforming and reduce the methane content
to approximately 0.3% on a dry gas basis. Maximum efficiency of the
overall reforming operation is required so that as much reforming as possible
be done in this reforming step. Utilization of combustion energy reduces
input of fuel gas to the Primary Reformer.
The air supply for the 2nd Reformer is provided by centrifugal steam turbine
driven Air Compressor (A-GB101).
A part of air is extracted from the intermediate stage of this air compressor to
entire complex use as instrument air.
- 2 -13 -
The purpose of preheating the air is to transfer a large part of the total
reforming conversion to the Secondary Reformer, thus reducing expensive
Primary Reformer catalyst volume in favor of the secondary reformer catalyst
volume. A small quantity of steam is continuously added to the air
preheating coil to protect it from burn out in case of upsets.
Reformed gas from Secondary Reformer passes directly to Reformed Gas
Waste Heat Boiler (A-EA102) in which 105 kg/cm2G saturated steam is
generated by cooling the process gas, and is cooled and fed to the 1st Shift
Converter (A-DC201).
These heat exchangers are provided with a by-pass in order to meet the
desired inlet temperature to the Shift Converter when the unit is new or
operating at reduced throughput. The boiler water required for this waste
heat exchanger is taken from Steam Drum (A-FA101).
4) Shift Conversion Section
The gas-steam mixture is introduced into the top of 1st Shift Converter (A-
DC201) in which a part of the CO in the process gas is converted to C02 with
an equivalent molar production of hydrogen. This vessel contains a single
bed of high temperature shift catalyst. The shift conversion reaction is a
reversible one. The equilibrium is favored by low temperature; rate of
reaction, however, is favored by high temperature. The design of the 1st
Shift Converter is based on reducing CO to a level of approximately 3% on a
dry gas basis. In passing through the 1st Shift Converter, the heat of reaction
causes the gas temperature to rise.
1st shift effluent then passes through heat exchanger, A-EA201, EA203
Methanator feed gas and boiler feed water is preheated in cooling the gas to
2nd Shift Converter (A-DC202).
A-DC202 inlet temperature is controlled by process gas by-pass flow of A-
EA203.
The partially shifted gas now enters 2nd Shift Converter (A-DC202). In
-2-14-
passing through the vessel, the CO content of the process gas is reduced to
approximately 0.4% on a dry gas basis.
Following the shift conversion step, the hot shifted gas is cooled by heating
hot potassium carbonate solution. Condensed water is removed from the gas
in the Process Gas K.O. Drum (A-FA301). The separated condensate in this
vessel is sent to the Process Condensate Stripper where contaminants are
removed before it is recovered.
5) Carbon Dioxide Removal Section
The removal of carbon dioxide from the raw synthesis gas is carried out in
single absorption stage by countercurrent contacting gas with hot potassium
carbonate solution in C02 Absorber (A-DA301). The absorber contains
packed beds. The hot potassium carbonate solution flows downward by
gravity while the raw gas flows upward through the tower.
The C02 in raw gas is removed by contact with "lean" hot potassium
carbonate solution in the packed part of the absorber. The absorber effluent
gas, of which C02 content is reduced to 0.1% by dry gas volume at the
absorber outlet, is fed to the downstream Methanator (A-DC401).
The total "rich" solution from the bottom of C02 Absorber is let down through
a valve and is delivered to the top part of CO, Regenerator (A-DA302).
The C02 Regenerator contains packed beds, where the C02 and other
dissolved gas in the solution are stripped by steam which is generated in
Process Gas Reboiler (A-EA303).
The regenerated solution, that is "lean" solution, is heat-exchanged against the
feed stream to the C02 stripper in the A-EA302, pumped up by the Solution
Pump (A-GA301) and then delivered to the top of the absorber after cooling
by heat exchangers, A-EA303.
The overhead vapor from C02 Regenerator is cooled to condense water vapor
by Overhead Condenser (A-EA306). The C02 is separated from the
- 2 -15 -
condensed water in Condensate Separator (A-FA302), further cooled C02
Direct Cooler (A-DA304) and sent to Urea Plant at 0.14 kg/cm2G, 40°C.
6) Methanation Section
The synthesis gas from C02 Absorber containing 0.1% C02 as expected and
0.5% CO on a dry basis flows to the Methanation Section for further
purification after passing through the Mist Trap (A-DA301) at the C02
Absorber Overhead.
The synthesis gas is preheated and flows to Methanator (A-DC401).
Preheating is accomplished by heat exchange against the 1st Shift Converter
effluent gas.
Following preheating of the C02 Absorber overhead gas, the stream is
delivered to the methanator, a vessel containing a bed of high-nickel base
catalyst that is very active for reacting CO, C02 (and even 02) with hydrogen
to form methane and water. In passing through the catalyst bed, from an
inlet temperature the exothermic heat of the methanation reaction raises the
temperature of the effluent. The total amount of carbon oxides leaving
Methanator will be less than 5 ppm.
The Methanator effluent is then cooled in the Methanator Effluent Economizer
(A-EA401), the Gas Final Cooler (A-EA402) and chiller and delivered to
Synthesis K.O. Gas Drum (A-FA401) at the Compressor Suction.
7) Synthesis Section
Following the cooling of the Methanator effluent, the purified synthesis gas is
delivered to the suction of Syn. Gas Compressor at a pressure of about 20
kg/cm2 G.
The synthesis gas sent from the Methanation Section is compressed in the first
stage of A-GB501 Synthesis Gas Compressor. The synthesis gas enters into
inter Stage Cooler for Syn. Gas Compressor and Syn. Gas Comp. Interstage
Chiller, where the synthesis gas is cooled for H20 condensation.
-2-16-
The compressed synthesis gas is mixed with the synthesis loop recycle gas
from Synthesis Converter. Then, the mixed is cooled by the Synthesis Cold
Exchangers and Ammonia Super Coolers for condensation of ammonia
product with refrigeration levels of -7°C and -29°C. H20 and C02, which are
poison for ammonia synthesis catalyst and remaining in the make-up synthesis
gas, are absorbed in to the condensed ammonia and removed from the
synthesis converter feed.
The converter effluent gas is cooled to -25°C in these exchangers and the
condensed ammonia is disengaged in Ammonia Separator.
A portion of the exit vapor from Synthesis Cold Exchanger is vented as
continuous purge to control the concentration of methane and argon as inerts.
These components would otherwise be built up in the system reducing the
effective synthesis pressure which would be reflected in lower conversion per
pass and production capacity. Then, the gas is recycled to the recirculator to
feed converter.
After it comes out from the compressor recycle stage for compression, the gas
is fed to A-DC501 Ammonia Synthesis Converter.
The converter feed is heated by Synthesis Hot Exchanger (A-EA501) and
enters to Ammonia Synthesis Converter (A-DC501).
Ammonia Synthesis Converter is vertical type and consists of a high pressure
shell containing the cartridge and Heat Exchangers. The cartridge is
cylindrical shell which fits inside the pressure shell of the vessel, leaving an
annulus between the two. The catalyst is contained devided sections. In
order to maintain all the catalyst at an optimum temperature for maximum
yield, cooling system is provided in the converter.
Located aside the cartridge is a heat exchanger which preheats the fresh inlet
gas against hot reacted gas from the catalyst bed. A bypass tube is provided
to permit introduction of feed gas without preheating and provides
temperature control to the top catalyst bed. Temperature indicators are
installed in the catalyst bed.
- 2 - 17 -
The feed gas flows between the pressure shell and the wall of the cartridge.
It serves as a cooling medium for the shell and thus receives preheat prior to
entering the exchanger. It enters the exchanger in the converter and is
preheated against hot effluent. Because of indirect cooling, the temperature
is reduced but the ammonia content is not diluted. In the presence of the
promoted iron catalyst, a portion of the total hydrogen and nitrogen combines
at a temperature of about 400 - 500°C and a pressure of about 120 kg/cm2G to
yield ammonia in a concentration of about 12% in the effluent from the last
catalyst bed.
From the outlet of converter shell, the converter effluent flows to Synthesis
Economizer (A-EB501). Then the converter effluent undergoes heat
exchange with the feed to the converter, lowering the converter effluent
temperature.
8) Refrigeration Section
A two-stage ammonia refrigeration system provides refrigerant for ammonia
condensation in the synthesis loop and synthesis gas compressor suction and
intercase chilling.
The refrigeration system consists of a two-case centrifugal Ammonia
Compressor (A-GC501) with Intercoolers, Ammonia Refrigerant Condenser,
Refrigerant Receiver and Ammonia Super Cooler. The two refrigeration
levels are approximately -7°C, and -29°C.
Ammonia vapor from the second case of the Ammonia Refrigerant
Compressor is cooled and condensed at 45°C and 17 kg/cm2G and flows to
Refrigerant Receiver.
Liquid from Refrigerant Receiver are flashed into Refrigerant Flash Drum at
32°C and about 12 kg/cm2G.
The net liquid from the Flash drum is fed into 1st Ammonia Super Cooler and
evaporated at -7°C and about 2 kg/cm2G.
A portion of the entering liquid is diverted and flashed through Syn. Gas
- 2 -18 -
Compressor suction and Interstage Chillers, providing the necessary
refrigeration for this service.
The interstage chiller is operated with a back pressure of about 3.5 kg/cnfG at
1°C on the refrigerant side in order to prevent icing on the process side.
The net liquid from the 1st Ammonia Super Cooler is fed into 2nd Ammonia
Super Cooler and evaporated at -29°C and about 0 kg/cnfG.
The vapors generated in the various chillers or super coolers are taken and fed
to the appropriate case or stage of the two case centrifugal Ammonia
Compressor (A-GC501). These vapors are compressed, condensed, and
returned to the receiver, thus completing the refrigeration cycle. Ammonia
Refrigerant Compressor is driven by the steam turbine.
9) Ammonia Recovery Unit and Purge Gas Recovery Unit (A-103-L)
The H P. purge gas from synthesis loop is fed to the High Pressure Ammonia
Scrubber and the flash gases from the Ammonia Product Letdown Tank is fed
to the Low Pressure Ammonia Scrubber (A-DA601) to recover the ammonia
vapor.
The High and Low Pressure Ammonia Scrubber recover the ammonia vapor
by water scrubbing. The aqua-ammonia solution from the bottom of High
Pressure scrubber is fed to the Ammonia Stripper and the solution of low
pressure scrubber is delivered to the Urea plant.
The aqua-ammonia solution from the bottom of the H P. ammonia scrubber
are fed to the ammonia Stripper to regenerate by reboiling with heat. The
M.P. steam is used for the reboiler heat which is supplied by the Ammonia
Stripper Reboiler.
The overhead gas from H P. Ammonia Scrubber is fed to the Hydrogen
Recovery Unit and the gas from L.P. Scrubber is used as fuel.
The recovered ammonia from the top of the Ammonia Stripper is mixed with
-2-19-
the main ammonia product. The stripped water from the bottom of the
stripper is cooled and returned to the top of the High Pressure Ammonia
Scrubber for reuse. H P. Ammonia Scrubber Feed Pump is used to return the
stripped water from the stripper to the High Pressure Ammonia Scrubber.
Purge gas recovery unit is applied to recover hydrogen from H P. purge after
scrubbed in the High Pressure Ammonia Scrubber. The overhead gases from
the Ammonia Scrubber is then sent to a cryogenic type purge gas recovery
unit, where in a major portion of the hydrogen is recovered for re-injection to
the synthesis loop.
Recovered hydrogen gas is returned to the suction of the Synthesis Gas
Compressor.
10) Process Condensate Stripping Section
The process condensate produced in the Ammonia Plant is sent to a process
condensate stripper, for recovery, after removal of the impurities.
The most parts of the impurities are removed from the process condensate in
Process Condensate Stripper of low pressure type.
The Stripper is the conventional low pressure type stripper.
The process condensate produced in the Ammonia Plant contains slight
amount of ammonia and methanol, both are formed as by-products in the
catalytic reaction, and C02 from the reformed gas is dissolved in the
condensate. The condensate is fed to the above mentioned stripper, where
the most parts of NH3, methanol and C02 are stripped by steam.
11) Steam System
The steam system is based upon high pressure steam generation at
approximately 105 kg/cnfG in Steam Drum (A-FA101) and combustion
chamber (A-EC108)
The steam system is arranged to provide good overall heat recovery from
- 2 - 20 -
process waste heat and consumption by the various turbine and process duties
consistent with good plant operability.
High pressure steam is generated by waste heat recovery in Secondary
Reformer Waste Heat Boiler, Combustion chamber and other process waste
heat economizers. High pressure steam is then, superheated in the reformer
convection.
Good waste heat recovery and therefore overall furnace efficiency is achieved
by further recovering waste heat in the convection section of the Primary
Reformer. Process waste heat recovery is achieved in the demineralized
water and high pressure boiler feed water preheat trains.
High pressure steam (103 kg/cm2G, 490°) is let down to the medium pressure
level through the high pressure casing of and the Syn. Gas Compressor
Turbine. This affords practical means of controlling the medium pressure
steam levels.
The medium pressure steam system (37 kg/cm2G) will provide steam for
process purposes, for the remainder of the turbine drivers on the Ammonia
Plant.
The low pressure steam (2 kg/cm2G) system is mainly used for depending
steam to achieve the necessary equilibrium conditions, in the Deaerator dome.
A Simplified Ammonia Plant Steam Balance (Existing) is shown in Fig.2.2-2.
- 2 - 21 -
-22-
to
.STEAMIMPORTH P. STEAM SUPERHEATING
STEAMDRUMCOMBUSTION
CHAMBER SYN. GASCOMPRESSORTURBINE
STEAMGENERATING
STEAM IMPORT
PROCESSSTEAM
M.P. STEAM
BACKPRESSURETURBINES
CONDENSINGTURBINES
BOILERFEEDWATER
HEATING (LOW PRESSURE LEVEL)
PROCESSHEATNG
SURFACECONDENSERS
MISCELLANEOUSSTEAMUSERS
VENT
POLISHER
DEAERATORBOILER
FEEDWATERHEATING
BOILERFEEDWATER
MAKE-UP
Fig.2.2-2 Simplified Ammonia Plant Steam Balance (Existing)
12) Other Facilities
(a) A naphtha-fired Start-up heater (A-BA501) is provided for activating a fresh
charge of catalyst in the Ammonia Synthesis Converter and for heating the
catalyst up to a temperature where the reaction is self-sustaining. Aqua
ammonia product during the synthesis catalyst reduction period is sent to the
effluent treatment unit or treated in the Urea plant.
(b) Boiler feed water treatment system including a deaerator, boiler feedwater
pumps and facilities for addition of hydrazine, phosphate and ammonia into the
boiler feed water is provided. Hydrazine Injection System, includes a tank
with a diaphragm pump. Phosphate Injection System, includes a tank and
diaphragm pump. Aqueous Ammonia Injection System, includes a tank and a
diaphragm pump. Deaerated boiler feed water is delivered to Steam Drum by
Boiler Feed Water Pump.
(c) The following are provided for the C02 Removal System:
- Solution Storage Tank (A-FB301)
- Make-up Tank (A-FA303)
- Solution Make-up Pump (A-GA303)
- Side Stream Filter (A-FD301)
- Preparation Filter (A-FD302)
The filter is fed a slipstream of the lean solution in order to remove any solid
contaminants which may be present in the circulating liquid.
(d) Liquid ammonia is cracked in the Primary Reformer to provide a source of
hydrogen for start-up of the desulfurizers, if hydrogen is not imported from
outside B.L.
Ammonia is pumped from the Ammonia Receiver by the Ammonia Injection
Pump (A-GA103) to the primary reformer and is mixed with the steam from
the boiler.
Hydrogen stream from the raw gas separator is recycled by mixing it with the
naphtha feed by Recycle H2 Compressor.
-2-23-
(e) Instrument Air Unit in the PLANT consists of 1+1 dryer system, wet air
reservoir with hold up of normal requirement in ammonia and urea plant and
dry instrument air reservoir with hold up of normal requirement in ammonia
and urea plant.
-2-24-
2.2.2.2 Urea Plant
1) General
The plant was originally designed to produce 1140 metric tons of prilled urea
per stream day by single train using MITSUI-TOATSU Total Recycle C
process, and standard operation in 1973.
The plant has been debottlenecked by ZIL several times, since its stand-up in
1973, to have the production capacity about 1300 - 1350 metric tons per day.
The plant can be divided into four sections, namely Synthesis, Purification,
Recovery and Crystallization, and Prilling sections.
2) Synthesis Section
Urea is produced by the highly exothermic reaction of ammonia and carbon
dioxide to form ammonium carbamate with slightly endothermic dehydration of
ammonium carbamate to form urea.
2NH3 + C02 <#> NH2COONH4
(ammonia carbamate)
NH2COONH4 <=> NH2CONH2 + H20
(urea)
The reactions are reversible. The principal variables affecting the reaction are
temperature, pressure, feed composition and reaction time.
The conversation of ammonium carbamate to urea takes place only in the liquid
phase, so high pressure is required. High temperature and pressure increase
the conversion to urea. Reaction conditions are about 197 - 200° C and 220 -
250 kg/cm2G. The conversion to urea is decreased by the presence of water
and increased by the presence of excess ammonia. Urea synthesis is achieved
in a vertical, high pressure vessel called Urea synthesis reactor, which has
sufficient volume to allow the synthesis reaction to approach equilibrium
condition closely.
Due to the corrosive nature of the reactants and reaction products in Urea
synthesis reactor, suitable protective linings are employed on all the surface in
-2-25-
contact with the reaction mixture. Urea synthesis reactor in this Plant is lined
with titanium.
Note : The Urea Reactor is proposed to be replaced by ZIL by a new Urea
reactor lined with stainless steel.
Normally, the reactants are also corrosive to stainless steel and titanium.
However, the addition of a small quantity of oxygen tends to passivate stainless
steel and titanium so that a satisfactory service life is obtained.
Since the overall reaction of ammonia and carbon dioxide to form urea is
exothermic, care must be taken to control the temperature in Urea synthesis
reactor. In ZIL Fertilizer plant, which uses Total Recycle C Process, the
reactor temperature is controlled by the combination of the following factors:
1. Excess ammonia to the rector
2. Recycle solution rate to the reactor
3. Pre heat temperature of liquid ammonia to the reactor
3) Decomposition Section
The products of the synthesis reaction consist of urea, biuret, (undesirable
dimer of urea), ammonium carbamate (hereinafter referred to as carbamate),
water and excess ammonia. Subsequent processing is required to separate
urea from reaction products.
In general, the processing proceeds in the following manner: carbamate,
excess ammonia and some water are removed by application of heat at reduced
pressure levels. Carbamate is decomposed to ammonia and carbon dioxide
gases.
NH2COONH4 = C02 + 2NH3
Decomposition is usually achieved at temperature of 120° C to 165° C.
Decreasing pressure favors decomposition as does increasing temperature.
During decomposition, hydrolysis of urea becomes an important factor.
Hydrolysis proceeds as indicated by the following reaction.
-2-26-
nh2conh2 + h2o C02 + 2NH3
Since hydrolysis consumes urea, which is the desired product, conditions are to
be closely controlled to minimize loss of product. Hydrolysis is favored by high
temperature, low pressure and long residence time. Decomposition equipment
and conditions of operation are therefore carefully selected to avoid these
factors in order to maintain high yield of urea.
Biuret formation is another factor to be considered both in decomposition and
finishing processes. At low partial pressure of ammonia and temperature
above 90° C, urea converts to form ammonia and buiret as in the overall
reaction below,
2NH2CONH2
(urea)
NH2CONHCONH2 + NH-
(biuret)
The reaction is reversible, and the principal variables affecting the reaction are
temperature, ammonia concentration and residence time.
The rate at which biuret is produced in molten urea and in concentrated urea
solution, with low ammonia concentration, is very rapid. But in the synthesis
step, the excess ammonia helps to keep the biuret content low.
Three decomposition steps, from 17.0 kg/cm2G, 2.5 kg/cm2G to atmospheric
pressure are used to remove carbamate and excess ammonia completely from
urea solution, before it flows to Crystallizer.
Some amount of air is blown through the solution at the lower part of Gas
separator to strip off the residual ammonia in the solution. The concentration
of the urea solution entering Crystallizer is about 65 - 70 wt. %.
4) Recovery Section
The basic differences between various urea processes, relate to the method of
handling of the unreacted ammonia and carbon dioxide gases from the
ammonium carbamate decomposers. It is not practical to compress the NH3-
C02 mixture and return this to the urea synthesis reactor.
Compression causes a recombination of ammonia and carbon dioxide to solid
-2-27-
ammonium carbamate and clogging the compressor. The methods for
recycling the unreacted gases can be classified into two types:
1. Separate and recycle as gases
2. Recycle in a solution or slurry form
In MITSUI-TOATSU Total Recycle C Process, the solution recycle process is
used. The NH3-C02 mixture gases from the decomposers are absorbed in water
and urea solution in the respective absorbers, and recycled back to Urea
synthesis reactor. The excess ammonia is purified in High Pressure absorber
and recycled separately to the reactor through Ammonia condensers, Ammonia
reservoir, Liquid ammonia feed pumps and Ammonia preheaters.
5) Crystallization & Prilling Section
The urea solution leaving the carbamate decomposers is vacuum crystallized
and urea crystals are separated by Centrifuge.
To use efficiently the heat of crystallization and to evaporate water at lower
temperature, vacuum crystallization is often used.
Crystals formed in the vacuum crystallizer are centrifuged, and then dried to
less than 0.3% moisture by hot air.
Dry crystals are conveyed to the top of Prilling tower passing through
Fluidizing dryer. There, the crystals are melted in a specially designed steam
heated melter.
The molten urea then flows through Distributors, and it is formed into droplets
and solidified in that shape by cooling air in the prilling tower. In order to
minimize biuret formation, the prilling section is designed to keep the residence
time of molten urea to a minimum.
It is also desirable to keep the moisture content of the melt as low as possible,
in order to produce hard prills and eliminate a drying step after prilling which
would weaken the prills and destroy the glassy surface. In this plant, the
crystals are dried to a moisture content as low as 0.2 - 0.3% before being sent
to Melter.
The prilled urea coming from the bottom of the tower is screened to remove
-2-28-
oversize prills, and then stored in the bulk storage.
6) Utilities
Major utilities required for the operation of Urea Plant are steam, cooling water
(CW) treated water (TW), Boiler feed water (BFW), Well water (WW),
Drinking water (DW), Plant air (PA), Instrument air (IA), Inert gas (IG),
Electric power (EP), Instrument power (24V) etc.
Steam
Steam is required for driving steam turbines of C02 booster compressor and
centrifugal carbamate pumps as well as for process heating.
Approximately 82 T/Hr of SH steam (33 kg/cm2G, 378° C) drawn from Utilities
is put through the C02 booster compressor turbine and is extracted at 12-13
Kg/cm2G and 260-270° C. Most of the extracted steam is used for process
heating in decomposers, melter etc. and balance is partly used in Hydrolyser
Stripper and about 16-20 T/Hr is sent back to utilities. Approximately 9 T/Hr
of SH Steam (37 Kg/cm2G, 371° C) drawn from ammonia plant is put through
centrifugal carbamate pump turbine and is totally condensed.
Cooling water
There are two cooling towers supplying cooling water to Urea plant namely
CT2 and CT3. While CT3 cooling tower supplied water only crystalliser
barometric condenser, CT2 cooling tower meets the requirement of all other
coolers and condensers in Urea Plant, CT2 system requires continues make up
and blow down which is done by water treatment plant. CT3 water is free
from chloride and normally CT3 system does not require a blow down
(however provision is available to blow down to stripper tank) but may require
a very small pure water make up which is done through addition of TW and
CT3 water is used as make up water for process in Ammonia Recovery
Absorber & Off Gas Absorber. A Small quantity is also used for washing of
crystallizer concentrator top part which goes into the process. In addition
CT3 water is used for gland cooling/flushing requirements of all pumps (except
centrifugal carbamate pump where treated water is used) and also for prilling
system washing.
-2-29-
Treated water
TW is supplied from water treatment plant and is used for rod packing cooling
of C02 compressor and for seal flushing of centrifugal carbamate pump.
Provision is available for adding TW to steam condensate tank, hot water tank
for plunger cooling of NH3 feed pumps.
Boiler Feed water (BFW)
Small quantity of BFW drawn from NH3 plant is used for desuperheating of
SML steam to melter.
Plant Air
Plant air, supplied by NH3 plant, meets the passivation air requirement in
reactor and High Pressure Decomposer and breathing air for air masks.
Instrument Air
Instrument air, supplied by ammonia plant meets the requirements for operation
of all instruments.
Inert Gas
Inert Gas supplied by ammonia plant, is used for purging NH3 reservoir and
high pressure decomposer during plant shut down/Start up, reactor draining,
reactor filling etc.
Electric Power
Electric power is supplied from power station and meets requirements of motor
drives and lighting.
-2-30-
2.2.3 Performance of Project Execution
(1) Engineering Performance
ZIL has a long experience of almost 30 years in operation of ammonia and urea
plants and has modified and improved the plants to increase their capacity. This
project incorporates revamp of existing plants, accordingly ZIL's experiences will
be useful for the revamp project. In addition ZIL carried out several projects
including DAP and Argon Recovery.
ZIL has a technical background and enough capabilities in executing CDM project
between Japan and India.
(2) Management Organization
A Chairman, a Managing Director and eight Directors are the board members.
Fertilizer division in Goa is managed by a executive president and five vice
presidents. Vice President Technical, Mr. D. Deshpande is in charge of the
project.
The management organization was established based on its long operation. Refer to
Fig. 2.2-3 organization chart.
-2-31-
(N>
U>K)
Vice Residmt CorpcrateFinance
R. S Ragtwan
GMFnaice 8 Accounting
L L Heda
Company Seaetary
R. Y. Prtll
Dy.GM Irtemd Audit
J. M. Lopes
Corpora e Vice Residait
Human Resources
D. P. Sinha
GM GMFinance Technical Servces
R. Ra^iurethan J R .Shgh
Chef Medicd Officer
Dr. A. A. Rabhudesd
Charm eh
K. K. Bria
ManagngD recta
H. S. Bava
Bcecuihe Resideit
Raman Machck
Vice Resident Technical
Bleep Deshpande
GMMan/as tiring & Sidhaan
Dy. GMAmrnoha UreaS
Utilles
V. N. S**ari
Dy.GMPH8RMH
V.K.Goyal
Dy GM Martei aice
AXE Gomes
Fig. 2.2-3
ZUARI INDUSTRIES LIMITED ORGANIZATION CHARTFERTILIZER DIVISION
Resdait Vice ResidentCorpaateAffairs
A V. Kanik V. Tcpa
Dy.GM Per samel 8IR
GMBusiness
Dadopment
L.M. Chan (has dcaai
Dy.GMRejects 8
Bigneaing
K G Dhume
GM - Corpaate Comnuricetons
Baium Baietji
Vice Res id ail Comma-art
GMMatoirts
GM
C V. Venkataamarti
Dy GM - Logistics 8 Strategic
Msrkrting
Dy. GM Marketing(RMOHydrsbad)
Dy. GMfvbrkeling (RMO Pune)
(3) Management Foundation and Management Policy
ZIL fertilizer division has been operated as a core business since their foundation.
Sales of fertilizers including Urea, NPK, DAP etc. was about 60 % of total sales
turnover in 1999-2000. The management foundation is mainly a fertilizer
business. Recently ZIL entered business of cement in 1995 and furniture in 1998
and his business field is expanding.
Some of ZIL's missions are as follows.
- Become one of the largest fertilizer players in India
- Contribute to local economy
Protect environment
ZIL fertilizer division became a zero effluent plant, first in the fertilizer industry in
1989.
The project is to revamp the existing ammonia and urea plants which are core
business of ZIL. Considering his management foundation and management policy
ZIL's could have an enough capability of the project execution.
(4) Financial Performance
The sales volume has been increasing for last ten years and ZIL’s financial
performance has been positive except the previous year. In the previous year the
financial performance was negative due to high feedstock price and reduction of
subsidy.
The major economic indicators of ZIL are listed below:
(Unit: million INR)
Year 1995-96 1996-97 1997-98 1998-99 1999-00
Turnover 7,334 6,994 9,578 8,513 13,924
Profit before Tax 843 525 617 143 A241
Profit after Tax 593 405 538 160 A216
Net Worth 2,422 2,740 3,562 3,624 3,354
-2-33-
ZIL's financial performance was relatively steady. ZIL belongs to Birla group,
which is No.2 financial group in India and the business field is expanding.
Therefore the financial performance could be enough for the project execution.
(5) Human Resources
The human resources of ZIL are enough, powerful and highly educated and having
many experiences from project development to operation. Number of employees
for last five years are listed below.
Year 1995-96 1996-97 1997-98 1998-99 1999-00
Employees 1,458 1,471 1,611 1,606 1,676
Most of the above employees are working in fertilizer division in Goa.
Therefore the project which will be executed in Goa could have enough human
resources.
(6) Project Execution Organization
Main frame for the project execution organization is illustrated below. The below
organization will include skilled man power in the past fertilizer projects.
Therefore the organization of ZIL could be sufficient for the project execution.
Contractor
Commercial
Manager
Zuari Ind. Ltd.
Project Manager
Mechanical ManagerOperation Manager
-2-34-
2.2.4 Outline of the Project
(1) Design Basis
The basis for designing the project are summarized below.
The design for the study is based on the conditions specified hereunder and the
utilities and battery limit characterized hereunder.
1) Capacity and operating hours
(a) Ammonia Capacity
The ammonia production capacity is 750 tons per day ±10 %.
(b) Urea Capacity
The urea production capacity is 1,300 tons per day ±10 %.
(c) Operating Hours
Annual operation period is 330 days (7,920 hours).
2) Product specification
(a) Ammonia
Quantity
750 MTPD±10 % of contained 100% ammonia at essentially even rate.
Condition to urea unit:
Ammonia will normally be passed directly to the Urea Unit as follows:
Composition
Suitable for Urea production and export but at latest equal to:
Ammonia
h2o
Oil
Pressure
99.9 % w/w min.
0.1 % w/w max.
5 ppm w/w max.
18 kg/cnfG min.
-2-35-
Temperature
Condition to storage:
10°C max.
The Ammonia Unit shall be capable of the total production of 750 MTPD +
10 %, going to storage directly at the following conditions:
Composition as above:
Pressure more than 18 kg/cm2G
Temperature 4°C max.
(b) Carbon dioxide (C02)
C02 will be sent directly to the Urea Unit at the following conditions:
Quantity
Approximately 1,157 MTPD, when producing ammonia at the rate of 750
MTPD with naphtha feedstock.
Composition
Suitable for urea production but at least equal to:
co2 99.0 % v/v min.
Hydrogen
Nitrogen
0.8 % v/v max.
0.2 % v/v max.
CH4+CO+Ar 0.02 % v/v max.
Sulfur essentially nil but in no event more than lppm
v/v
Abs. Chemical essentially nil
h2o Saturated
Pressure 0.14 kg/cm2G
Temperature 40 °C
(c) Urea
Urea will be produced as prill with the following specification.
-2-36-
46.4 % by weight min.
0.3 % by weight max.
0.3-0.6 % by weight
4 ppm by weight
98 % by weight min.
3) Specification of raw materials
Total Nitrogen
Moisture
Biuret
Iron
Size (8-24 mesh)
Feedstock Naphtha Property
The analysis data on August 19, 2000 is adopted for design:
Property Unit MethodIS1448 Limits Analysis
Result
Appearance - Visual Clear & Bright
Clear & Bright
Colour - Visual Colourless Colourless
Density @ 15°C - P-16 Report 0.7204
Distillation
a) I B P. °C P-18 Report 48.0
b)50% recovered °C P-18 130.0 Max. 93.0
c) Final Boiling Point °c P-18 180.0 Max. 151.0
R.V.P. @ 37.8°C kg/cm2 P-39 0.7 Max. 0.48
Residue on evaporation mg/lOOml P-64/P-29 5.0 Max. 1.5
Total Sulphur
(Lamp Method)% by wt. P-34 0.15 Max. 0.03
Aromatics % by vol. P-23 20.0 Max. 9.4
Olefins % by vol. P-23 1.0 Max. 0.5
Calorific Value
(Calculated)BTU/Lb P-7 18,360 Min. 20,357
Net Calorific Value kcal/kg - - 10,580
Carbon & Hydrogen
Ratio(Calculated)- - 6.5 Max. 5.58
Lead Content ppb IP-224 200 max. 30
-2-37-
Remarks: Meets specification w.r.t. above tests
Lab. Environmental Cond. Temp. 25-30°C, RH 45-80%
Feedstock Natural Gas Specification
Composition
Nitrogen 1.0 mol %
Methane 90.0 mol %
Ethane 5.0 mol %
Propane 3.0 mol %
Buthane 1.0 mol %
Net heat value
Pressure
Temperature
9,393 kcal/Nm3
40 kg/cm2G min. at the battery limit of ammonia
plant
Ambient
4) Specification of Utilities
(a) Steam
LP steam
Pressure (kg/cm2G)
Temperature (°C)
MP steam
Pressure (kg/cm2G)
Temperature (°C)
Hp steam
Pressure (kg/cm2G)
Temperature (°C)
Super HP steam
Pressure (kg/cm2G)
Temperature (°C)
Ammonia Plant Urea-Plant
2 2.5/5.0
210 - 230 sat./sat.
13.5 21.5/20
360 318
37 43
390 385
103
490
Utility
3.5
240
13
260
44
380
-2-38-
105
490
(b) Raw water
Pressure 3 kg/cnfG
Temperature ambient
(c) Electricity
Voltage
Voltage deviation
Frequency
3.3 kV / 440 V / 220 V
3.3 kV / 440 V / 220 V±5%
50 Hz
(d) Instrument power and control system
Voltage 220 V / 110V (AC) / 50 Hz
24 V (DC)
(e) Instrumentation air
Pressure 6 kg/cnfG
Temperature
Quality
Dew point
ambient
free of oil, water and dust
-20°C (under 6 kg/cnfG)
(f) Cooling Water
Supply pressure
Supply temperature
Return temperature
4 kg/cnfG
32°C
42°C
(g) Plant air
Pressure 6 kg/cnfG
Temperature ambient
-2-39-
(2) Outline of the Plant
1) Ammonia Paint
Several modifications are planed in order to achieve the target energy saving.
These modifications are grouped into 7 sections and explained as below.
Process for other section remains the same as existing as already explained in
the previous paragraph 2.2.2.
Carbon Dioxide Removal Section
Synthesis Gas Drying Section
Synthesis Section
Steam System
Process Condensate Stripping Section
Natural Gas Receiving Section
Bulk Material
An Ammonia Simplified Flow Diagram (After Revamp) is shown in Fig.2.2-4.
-2-40-
1ST REFORMER 2ND REFORMER SHIFT CONVERTERS
COMB. CHAMBER
AIR COMPRESSOR
STEAMFEEDNAPHTHA—►
COMB. AIR
STEAM METHANATOR CO, REGENERATORCO,ABSORBERDRYER
CO, GAS TO UREA
PROCESSS CONDENSATESYN. GAS COMPRESSOR
AMMONIACONVERTERS D—(a)—CL
AMMONIA COMPRESSORPRODUCT LIQUID AM MONIA
Fig.2.2-4 Ammonia Simplified Flow Diagram (After Revamp)
(a) C02 Removal Section
Process Feature of CO, Removal section
One of the largest consumers of energy in the ammonia process is carbon
dioxide removal. Therefore, a significant attention has been given to this
section of the Plant. A considerable amount of energy can be saved through
more advanced and efficient design.
In the energy saving modern ammonia plant, three C02 removal process can be
adopted and the feature of each C02 removal process is shown below.
BASF aMDEA process is selected due to the advantage of energy saving and
superiority for the environment.
LoHeat Benfield with ACT-1, improved activator, process can be selected as
alternate due to its chemical availability and it’s moderate energy saving
performance. BASF aMDEA process has disadvantage on the cost of chemical
but it is considered that the energy saving effect and superiority for the
environment can cancel the disadvantage.
Selexol process is not recommended because C02 recovery rate has limit that
does not suit to the combination of the Urea plant.
LoHeate Benfield aMDEA Selexol
Licensor UOP BASF ucc
Solution K2CO3 29-30 wt.% DEA 2.9-3.0 wt.% V205 0.7-1.0 wt/%
MDEA 35-40wt.% Dimenthyl ether of Polyethylene Glycol (DMPEG)
Absorption Type Chemical Physical/Chemical Physical
Regeneration Steam Reboiler Flash &Steam Reboiler
Flash & Air Stripping
Regeneration Heat 800 - 850 (kcal/Nm3 - C02)
350 - 550 (kcal/Nm3 - C02)
. -
C02 Recovery Rate 100% 99.0% (1) 75% (2)
C02 Purity (as dry) 99.0-99.3 vol.% 99.5 vol.% 98.5 vol.%
No. of Experience in Ammonia Plant
63 53 10
-2-42-
Note: (1) If the H P. flash gas is recycled to absorber inlet, 100% recovery can
be attained.
(2) Remaining 25% C02 is stripped by air.
Process Description CQ2 ^Removal Section
The removal of carbon dioxide from the raw synthesis gas is carried out in two
(2) absorption stages by countercurrent contacting gas with aMDEA solution in
C02 Absorber (A-DA301). The absorber contains a total of four (4) packed
beds, two beds of structured packings and two beds of slotted rings. The
aMDEA solution flows downward by gravity while the raw gas flows upward
through the tower.
The bulk of C02 in raw gas is removed by contact with “semi-lean” solution in
the lower packed part of the absorber and the rest by contact with “lean”
solution in the upper packed part.
The absorber effluent gas, of which C02 content is reduced to approximately
1,000 ppm by dry gas volume at the absorber outlet, is fed to the downstream
Methanator (A-DC401).
The total “rich” solution from the bottom of C02 Absorber is let down through
Hydraulic Turbine (A-GA301C-HT) which drives Solution Pump (A-GA301C)
and is delivered to HP Desorber (A-DA305). The flashed liquid is then
delivered to LP Flash section of C02 Regenerator (A-DA302) where most of the
dissolved C02 is stripped from the rich solution.
The flash gas from the HP Desorb er (A-DA305) is fired in Combustion
Chamber (A-EC108).
Semi-lean solution from the bottom of LP Flash section of C02 Regenerator is
split into two streams. One stream is fed to the mid-section of C02 Absorber
by Solution Pump (A-GA301A,B,C) and the other stream is preheated and
delivered to the top of C02 Stripping Section of C02 Regenerator (A-DA302)
pumped up by the semi-lean solution Pump (A-GA306A,B). The stripping
section contains two (2) packed beds of slotted rings, where the remaining C02
-2-43-
and other dissolved gas in the semi-lean solution are finally stripped by stream
which is generated in Process Gas Reboiler (A-EA301).
The regenerated solution, that is “lean” solution, is heat-exchanged against the
feed stream to the C02 stripper in the Solution Heat Exchanges (A-EA302)
pumped up by the Lean Solution Pump (A-GAS05A,B) and then delivered to the
top of the absorber after cooling by solution cooler (A-EA303).
C02 stripping section overhead vapor enters LP flash section (A-DA302 upper
part) and promotes the stripping of C02 from the rich solution. The overhead
vapor from LP flash section (upper part of A-DA302) is cooled to condense
water vapor by Regenerator Overhead BFW Heater (A-EA308) and Overhead
Condenser (A-EA306). The C02 product is separated from the condensed
water in Condensate Separator (A-FA302), Further cooled in C02 Direct Cooler
(A-DA304) and sent to Urea Plant.
The condensed water is pumped up by the Regenerator Reflux Pump (A-
GA302A,B) and then returned to the L.P. flash section of A-DA302.
Side Stream Filter (A-FD301) is reused to maintain solution quality. A
provision for intermittent anti-foam injection is also reused for the event of
foaming occurrence.
All available heat of effluent gas from 2nd Shift Converter is consumed for
solution regeneration heat by the Process Gas Reboiler in the existing plant.
This regeneration heat is considerably reduced by the application of aMEDA
process. The surplus heat of 2nd Shift Converter effluent gas is recovered by
heating boiler feed water with LTS Effluent HP BFW Heater (A-EA311) and LP
BFW Heater (A-EA312).
For the revised process scheme as described as above, following addition and
modification of equipments is required.
Addition of semi lean solution line
Internal modification of C02 Absorber (A-DA301) and C02 Regenerator (A-
DA302) for semi-lean solution lines.
Addition of HP Desorb er (A-DA305)
Addition of LTS Effluent HP BFW Heater (A-EA311) and LP BFW Heater (A-
-2-44-
EA312)
Addition of Solution Pump (A-GA301C) and Hydraulic Turbine (A-GA301C-
HT)
Addition of Lean Solution Pump (A-GA305A,B) and Semi-lean Solution Pump
(A-GAS 0 6 A, B)
(b) Synthesis Gas Drying Section
Process Feature of Molecular Sieve Dryers
Molecular sieves are used in this design to remove water and trace amounts
of carbon dioxide, thus eliminating poisons to the synthesis catalyst and
thereby allowing the makeup synthesis gas to be routed directly to the
ammonia converter. This operation is used to reduce power requirements
in both the synthesis recycle loop and the ammonia refrigeration system.
By routing the fresh make up gas (along with recycle gas) to the converter, a
reduction in loop pressure prop can be achieved, which in turn reduces
recycle power requirements. By not mixing the fresh make up with
converter effluent gas prior to chilling for ammonia recovery, the
concentration of ammonia is increased in the chilled gas, thereby reducing
refrigeration requirements necessary for ammonia recovery.
The specification of Molecular Sieve Dryers is as follows;
Adsorbent Synthetic zeolite
Shape Pellet (typical)
Excepted effluent content C02 less than 1 ppm vol.
H20 less than 0.1 ppm vol.
Experience with such molecular sieve drying systems dates back a number
of years. Molecular sieve systems have been designed for such
installations at not only ammonia plant but also olefin plants, LPG plants,
and large helium extraction plants.
-2-45-
Process Description of Synthesis Gas Drying
Following the cooling of the Methanator effluent, the synthesis gas is
delivered to the suction of Syn. Gas Compressor.
The synthesis gas sent from the Methanation section is compressed in the
first stage of Synthesis Gas Compressor (A-GB501) and enters Syn. Gas
Comp. Intercooler and Syn. Gas Comp. Interstage Chiller, where the
synthesis gas is cooled for H20 condensation. Then, the H20 and C02
remaining in the gas are removed by Molecular Sieve Dryers (A-
DA501A,B) to the C02 content of 1 ppm or less and H20 content of 0.1 ppm
or less.
The Dryers are comprised of two vessels and are arranged so that while one
is employed for C02 and H20 removal, the other can be regenerated by the
tail gas from Purge Gas Recovery Unit with Molecular Sieve Regeneration
Heater (A-EA505). The gas used for the regeneration is reused a as fuel.
A provision of regeneration of the Dryers is made alternatively with the
purified synthesis gas from the vessel employed for H20 and C02 removal.
(c) Synthesis Section
Current Performance of Synthesis Converter
The current operation is defined by plant data from September 5 and 6, 2000,
and analytical data from August 24 through September 6, 2000. This data
was obtained during first plant visit for the feasibility study.
An overall material balance for the current operation of the synthesis loop
shows reasonable closure. The flow meters for recycle gas and converter
feed, when corrected for stream conditions, show 10-17 percent lower flow
than calculated from the ammonia contents and the ammonia production.
A heat balance across the converters indicates an even lower recycle rate,
and we had difficulty reconciling the plant data with the performance curve
for the recycle compressor. Clearly, the current operation needs to be
verified during a firm design phase.
To determine the current catalyst activities, a kinetic simulation of each
-2-46-
converter bed was performed. Calculated flow rates, the ammonia contents
from the laboratory data, and the temperatures from the plant log was used.
One free variable is needed in order to obtain heat balance closure, and the
inlet temperature to bed 1 to change in the simulation was allowed. This is
because the plant readings in train B appear incorrect, making the readings
from train A suspect also.
Process Description of Synthesis Section
The modification scheme of Synthesis Section is to install a small converter
with KBR(Kellogg Brown & Root)’s proprietary KAAP(Kellogg Advanced
Ammonia Process) catalyst, downstream of the existing two parallel
converters. With the KAAP converter, it will be possible to reach an
ammonia concentration of 17 volume-percent in the converter effluent, as
compared to the present 11.8 percent. Therefore, the recyle rate can be
reduced substantially, resulting in reduced compressor power.
A proven design for the KAAP converter and the new feed/effluent heat
exchanger are planned. A new boiler feed water heater is also needed.
For the KAAP catalyst to retain good efficiency, it is necessary to install
molecular sieve dryers on the makeup syngas as part of the modification.
Once the makeup syngas is dry, it can be routed directly to the synthesis
converters, instead of being routed to the ammonia separator. This results
in a lower ammonia content of the feed to the converters, thereby allowing
more conversion per pass and therefore lower recycle rate and reduced
energy consumption. During studies on other plants that this benefit
essentially justifies the cost of the dryers, regardless of the use of KAAP
catalyst.
MAKEUP GAS: The composition of the makeup gas is adjusted slightly,
so that the feed to the converters has a hydrogen-to-nitrogen ratio less than 3.
That is more optimum for the combination of iron and KAAP catalysts, as
KAAP catalyst has better performance at lower H/N ratios.
The makeup gas is dry and free of carbon oxides.
-2-47-
The makeup gas joins the recycle gas and flows to the existing converters.
That will require a piping change. Water cooler A-GB502C3 can be
retired.
EXISTING CONVERTERS: Using the catalyst activities derived from the
plant data, the optimum temperature profile in each catalyst bed of the
exiting converters was determined. The load was also shifted, so that
converter B takes 55 percent of the total feed. That gave a (very slight)
improvement in overall conversion. The total stream leaving the existing
converters can reach 14.5 percent ammonia at the lower recycle rate.
The temperature of effluent from the existing converters will be higher than
the present. The reason is that when the recycle rate is decreased, the heat
of reaction is distributed over less total gas. Also, the conversion per pass
is increased.
NEW EQUIPMENT: The effluent from the existing converters flow
through a new KAAP feed/effluent exchanger, through a bed of KAAP
catalyst, through the feed/effluent exchanger, and through a new boiler feed
water heater. Therefore, the converter effluent flows through the existing
heat exchanger train.
KAAP FEED / EFFLUENT EXCHANGER: The new KAAP feed-effluent
heat exchanger is located together with the KAAP catalyst in a single vessel.
Similar designs have been used in three prior KAAP retrofit projects. The
exchanger heats the KAAP feed to the optimum reaction temperature. A
bypass is provided for control of the KAAP catalyst feed temperature.
KAAP CONVERTER: The KAAP catalyst is arranged in a radial bed.
The volume is chosen to give a reasonable approach to equilibrium in the
converter effluent, or, in other words, to obtain maximum practical
conversion from a catalyst bed. It is possible to reach an ammonia content
of 17 volume percent in the KAAP converter effluent with a reasonably low
amount of KAAP catalyst. This allows the recycle rate in the synloop to be
decreased substantially.
-2-48-
Connections are provided from the startup heater and from synthesis hot
exchanger A-EA501, for warming up the KAAP catalyst. This provides
flexibility for cold and warm start.
NEW BOILER FEED WATER HEATER: The effluent from the
feed/effluent exchanger is available at higher temperature than the design
temperature of the inlet to the existing synthesis economizer A-EB501.
Therefore, a new heat exchanger is needed between the two. It is
anticipated that it can be useful as a boiler feed water heater.
SYNLOOP PURGE: The existing purge gas recovery unit should be
operated at full capacity, 12,000 Nm3/hr. That will constitute a purge of
5.2 volume percent of the recycle gas. The resulting inerts level in the
converter feed will be 7.3 volume percent.
PRESSURE PROFILE: The current pressure drop in the synthesis loop is
10 kg/cm2. At the new lower recycle rate, the pressure drop in the existing
equipment will be about 3 kg/cm2. The new equipment will add about 1.3
kg/cm2, for a total pressure drop of about 4.3 kg/cm2.
SYNTHESIS GAS COMPRESSOR AND AMMONIA COMPRESSOR:
The new compressor loads require modifications to the compressor internals
of both of Synthesis Gas Compressor and Ammonia Compressor. The
compressor internals of both two compressors should be replaced in order to
bring the compressor up to state-of-the-art efficiency.
(d) Steam System
Steam turbine for Synthesis Gas Compressor
Synthesis Gas Compressor has been driven by two steam turbines. One is
SX-SH (103 - 37 kg/cm2G) back pressure type and the other is SH (37
kg/cm2G) condensing type steam turbine. After the modification of
synthesis section including the addition of molecular sieve dryer, required
power for the Synthesis Gas Compressor is reduced considerably and can be
-2-49-
supplied by only SX-SH back pressure steam turbine. Therefore SH
condensing steam turbine is no longer required and disconnected.
Steam Turbine for Fans
Air Blower (Forced Draft Fan) and Induced Draft Fan has been driven by
steam turbines. These steam turbines are small and efficiency is low or
energy consumption is high. These steam turbine are replaced by motors to
reduce the energy consumption.
A Simplified Ammonia Plant Steam Balance (After Revamp) is shown in Fig.
2.2-5.
-2-50-
Fig.2.2-5 Simplified Ammonia Plant Steam Balance (After Revamp)
(e) Process Condensate Stripper Section
Overhead vapor from the existing low pressure type process condensate stripper
has been condensed by condenser with cooling water. Therefore, heat of
overhead vapor has been discarded. Moreover, Impurities of process
condensate such as ammonia, methanol and C02 are non-condensable gas in the
overhead vapor and have been discharged to the atmosphere.
By applying high pressure type condensate stripper, overhead vapor is utilized
as reforming steam. Thus, heat of overhead vapor is fully recovered.
Impurities in the overhead vapor is reformed in the 1st reformer and is not
discharged to the atmosphere. High Pressure Condensate stripper System
consists of following equipments.
A-DA306 Process Condensate stripper
A-EA314 Condensate Stripper Feed/Effluent Exchanger
A-EA315 Stripped Condensate Cooler
A-GA307A,B Process Condensate Pump
(f) Natural Gas Receiving Section
In case the natural gas in future will be used as a feedstock, the natural gas
feed and fuel from NG Receiving and Meeting Station initially pass through
Feed Gas K.O. Drum where entrained liquids and solids are removed.
Then, a part of natural gas is divided as fuel. Natural gas as feedstock is
delivered to the Feedstock Preheater.
(g) Bulk Material
Complying with requirements after the plant modification, modification or
addition of system of instrument, electricity and piping is required.
-2-52-
2) Urea Plant
General
Fig. 2.2-6 shows overall block diagram of the renovated urea plant.
The existing conventional urea process plant is renovated with the latest
stripping process by adding the following high pressure equipment operated at
principally same pressure as reactor:
- Stripper which decomposes un-reacted ammonium carbamate to separate
ammonia and C02 as gas phase
- Carbamate Condenser which condenses the ammonia and COz gas to form
ammonium carbamate and urea, and to fully recover the condensation heat
by generating low pressure steam
The targeted production capacity is 1,300 MTPD ±10%, basically maintaining
the same capacity as before renovation. In the renovated process, the
synthesis pressure at 155 Kg/cm2G is selected to reduce energy to pressurize
ammonia and C02 as raw materials and recycle ammonium carbamate solution
up-to the synthesis pressure. The addition of Stripper and Carbamate
Condenser further reduces operating load in downstream sections, resulting in
additional reduction of energy requirement.
Steam turbine for C02 booster compressor is replaced from back pressure
turbine to extraction-admission-condensing turbine to supply middle pressure
steam for heating Stripper and to utilize low pressure steam generated by heat
recovery in Carbamate Condenser.
Purification and recovery sections require minor modifications to meet the new
operating conditions after process renovation.
The following outlines the process of the renovated Urea Plant consisting of
five sections, namely Synthesis, Purification, Recovery and Prilling Sections.
-2-53-
NH3 )ir MODIFICATION OF STEAM TURBINE
to
PURIFICATION
SYSNTHESIS (ACES 21)
CC02)nrC02
CONIPRESSION
RENOVATION
MINORMODIFICATION
► RECOVERY
1
CRYSTALLIZATIOI
IPRILLING
T
MINORMODIFICATION
1,300 T/D UREA
Fig. 2.2-6 Urea Process Renovation Scheme
CP2 Compression Section
Fig. 2.2-7 shows a schematic flow diagram of the C02 compression section.
The make-up C02 gas is compressed up to the synthesis pressure by the steam
turbine driven centrifugal type C02 Booster Compressor and the reciprocating
C02 Compressor. The most part of C02 gas is fed to Stripper for C02
stripping purpose and remainder is fed to the reactor. C02 Compressor also
feeds anti-corrosion air for the synthesis loop
Fig. 2.2-8 shows a schematic flow diagram of hydrogen removal facility. Since
the oxygen content becomes ten times of that before process renovation,
hydrogen contained in the C02 gas is removed by catalytic combustion reaction
with oxygen to prevent flammable gas mixture formation due to hydrogen and
oxygen in the synthesis section.
Synthesis Section
Fig. 2.2-9 shows the process flow schemes of the synthesis section and C02
compression section respectively. The major equipment of the synthesis section
are Reactor, Stripper, Carbamate Condenser and HP Ejector. Urea is
synthesized by the reaction of liquid ammonia, gaseous C02 supplied from
Ammonia Plant, and the recycle carbamate solution from the Recovery Section
of Urea Plant. Synthesis urea solution is sent to the Purification Section for
further removal of ammonium carbamate and excess ammonia, after being
stripped by gaseous C02. The make-up liquid ammonia is pumped up and fed to
Reactor through Ammonia Preheater and HP Ejector by Ammonia Feed Pump.
HP Carbamate Ejector using high pressure liquid ammonia as the motive fluid
pumps carbamate solution from carbamate condenser to Reactor.
The recycle carbamate solution coming from the Recovery Section is pumped
up by a centrifugal type Carbamate Feed Pump, and is fed to Carbamate
Condenser.
Reactor is operated at 155 Kg/cm2G and 182 - 184°C, and at NH3/C02 molar
ratio of 3.7. Reactor is a vertical tower with internal baffle plates, and its
interior wall is lined with special stainless steel of urea grade. The operating
-2-55-
- 56-
REPLACE+ STEAM TURBINE FOR
CO2 BOOSTER COMPRESSOR
0
0
In)
C02FROM AMMONIA PLANT
21.5 Kg/cm2 STM ______ |
TO SYNTHESIS SECTION
i▼
C02 TOSYNTHESIS SECTION
STEAM TURBINE FOR C02 BOOSTER
COMPRESSOR
TURBINE C02 BOOSTER CONDENSER COMPRESSOR C02 COMPRESSOR
Fig. 2.2-7 Urea C02 Compression Section
DEHYDROGEN COLUMN CO2 GAS COOLER
1 jL>\
H2 02 ANALYZER
Fig. 2.2-8 Urea Hydrogen Removal
ts>
Uloo
REACTOR STRIPPER CONDENSER
TO HP ABSORBER COOLER
ADD
BFW LPSTEAM
STRIPPERCARBAMATE CONDENSER HP EJECTOR
MODIFYNH3 PREHEATER C02 BOOSTER TURBINE
0
TO PURIFICATION SECTION
BFROM HP ABSORBER COOLER
C02 COMPRESSOR NH3PUMP CARBAMATE FEED PUMP
Fig. 2.2-9 Urea Synthesis Section
pressure of Stripper and Carbamate Condenser are substantially same as that of
the Reactor.
The synthesis urea solution, after attaining high once-through C02 conversion
in Reactor, is led to Stripper. The synthesis urea solution from Reactor is
stripped by C02 gas and heated in the falling film type heater. Major volume
of ammonium carbamate and excess ammonia contained in the synthesis urea
solution is decomposed and separated in Stripper. The stripped off gas is sent
to Carbamate Condenser. After the C02 Stripping in Stripper, the solution
leaving Stripper is sent to Purification Section.
In Carbamate Condenser, NH3 and C02 gas condense to form ammonium
carbamate and urea in the shell side. The condensation heat is utilized to
generate 5.5 Kg/cm2G steam in the tube side. A packed bed is provided at the
top of carbamate condenser to absorb uncondensed ammonia and C02 gas in the
recycle carbamate solution from the Recovery Section. The gas from top of
the Carbamate Condenser is fed to HP Absorber Cooler for further recovery of
ammonia and C02 gas and the solution from the bottom is fed to Reactor
through HP Carbamate Ejector.
Purification Section
Fig. 2.2-10 shows a schematic flow of purification section. To utilize the
generated low pressure steam effectively in purification section, Preheater for
HP Decomposer heated by the low pressure steam is added.
Recovery Section
Fig. 2.2-11 shows a schematic diagram of recovery section. One shell of
Ammonia Recovery Absorber is added to absorb ammonia gas as inert gas
quantity increases after process renovation.
Crystallization and Prilling Sections
Crystallization and prilling sections are maintained same as before renovation.
-2-59-
PREHEATERFOR HPD HP DECOMPOSER LP DECOMPOSER GAS SEPARATOR
N>
S
TO HP ABSORBER COOLER TO LP ABSORBER TO OFF GAS CONDENSERi-------- ► |------“► j-------- ►
♦ PREHEATER FOR HPDFROM STRIPPER
FROM OFF GAS ABSORBER - STM.
TOCRYSTALLIZER
Fig. 2.2-10 Urea Purification Section
HP ABSORBERNH3 RECOVERY
ABSORBER
HP ABSORBER COOLER NH3 CONDENSER
ADDITIONAL NH3 RECOVERY
ABSORBER
wOS
III
NHa FROM NR & NC
FROM LP ABSORBER
FROM HP DECOMPOSER
CW
NH3
TO CARBAMATE FEED PUMP
▲ WATER^ ------
ifATi CW
ADD• ADDITIONAL NH3 RECOVERY I
ABSORBER *
AQUA. NH3
Fig. 2.2-11 Urea Recovery Section
Steam System
Fig. 2.2-12 shows a simplified steam system. Steam system is optimized by
utilizing the generated low pressure steam for process heaters instead of 12 K
steam except Stripper. Excess low pressure steam is utilized for admission of
Steam Turbine of C02 Booster Compressor. Part of 21.5 K steam is exported to
be used for steam turbine for CT-2 pump. Total steam import to Urea Plant is
thus reduced by 35.85 t/h from that of existing plant.
-2-62-
N>
a
EXISTING1297 T/D
90.3 T/H (1.67 T/T-U)
4.85 T/H (0.089 T/T-U)
24.2 T/H
1.65 T/H
E40.31 T/H
12 KG USER
7 KG
28.1 T/H
5 KG USER
RENOVATED1300 T/D
59.3 T/H(1.095 T/T-U) r—
"► TO HS & CT-2
____„ 17.09 T/H" (0.316 T/T-U)
4 KG
6.61 T/H
3 KG 3 KGUSER USER
Fig. 2.2-12 Urea Steam System
(3) Plant Layout
1) Outline of existing Plant Layout
A conceptual layout of the existing plants in Zuari Industries Limited (ZIL) is
shown in Fig 2.2-13. Ammonia and Urea plants adjoin and these two plants
are connected through pipe rack which runs in the center of the plants from
north to south.
In the existing plants, many modifications had been carried out by ZIL by
themselves for the main purpose of capacity increase. Approximate 25
additional equipment had been already installed.
2) Outline of renovated Plant Layout
The renovated plant layout was determined considering the followings based on
the result of site survey.
- Modification in the existing plants should be minimized.
- Cost for piping material and construction, which is necessary for the
renovation, should be minimized.
- Accessibility inside the plant, which is at least necessary for plant operation,
should be kept after the renovation.
- Interference between the existing underground piping and newly added
equipment/structure should be prevented.
- Constructibity of newly added equipment should be considered at the
construction stage of the actual project.
- Availability of free space in the existing plants (on pipe rack, for example) to
install newly installed piping should be examined.
Renovated plant layout was submitted to Zuari Industries Limited (ZIL) at the
2nd site survey, and some comments were provided from view point of their
usual maintenance work. The renovated plant layout was finalized in
accordance with discussion between ZIL and TEC.
Sections in which plant layout will be renovated are stained in Fig 2.2-13.
The detail of the renovation for each section is explained as follows:
-2-64-
N>
8
Ammonia Plant I Urea Plant◄----------- ;-----------►
Main pipe rack
Crystallizationsection
Prilling section
Control room / Switch room
section to be renovated
Fig2.2-13 Conceptual Figure of Existing Plant Layout in Zuari Industries Limited (ZIL)
(a) C02 Removal section (Ammonia plant)
One tower, two heat exchangers, and two pumps (one of them is driven by a
turbine) are newly installed to apply aMDEA technology and new pipe rack is
provided between newly added equipment and the existing plant. Furthermore,
modification of internal is required for two existing towers.
(b) Compressor section (Ammonia plant)
Three compressors, which are all driven by stream turbines, are available in this
section. Two compressors and one turbine of these compressors driven by
turbines are modified because operating condition will be changed after
renovation.
Molecular Sieve Dryer and a succeeding heat exchanger are newly installed at
free space available in the east of this section.
(c) Process condensate stripping (PCS) section (Ammonia plant)
HP Condensate Stripper section which consists of one tower, two heat
exchangers, and one pump is newly installed at free space available in the west
of this section.
(d) Reforming section (Ammonia plant)
Burners for Reformer and Heater are replaced because raw materials for
producing ammonia is changed from naphtha to natural gas.
(e) Synthesis section (Ammonia plant)
An ammonia converter and a succeeding heat exchanger are newly installed at
free space available in the west of this section.
(f) Synthesis section (Urea plant)
To apply ACES 21 technology for urea synthesis, one tower, one reactor, three
heat exchangers, four drums, one pump, and one filter are newly installed at
free space available in the east of this section.
Existing underground piping is available under the free space where these new
equipment is installed. However, since there is no other space to install new
equipment, it is determined that new equipment is installed above the existing
underground piping considering interference between underground piping and
foundation of newly installed structure. TEC has experiences in the past
-2-66-
projects to install equipment above underground piping, and no technical
problem could not be expected.
(g) Compressor / Pump section (Urea plant)
The existing turbine to drive a compressor in this section is replaced to new one
of extraction-admission-condensing type. Additionally a surface condenser
for this new turbine is installed at the north of compressor/pump building with
a structure.
- 2 - 67 -
(4) Plant Cost
EPC cost of the revamp plants was jointly estimated by TEC and Toyo Engineering
India Ltd. (TEIL) based on many experiences of fertilizers plants in India.
Estimated plant cost is tabulated below.
Category Estimated Cost (MUS$)
Engineering 9,404
Equipment and Material 38,264
Construction 8,679
Others 2,530
Total Plant Cost 58,877
- 2 - 68 -
(5) Raw Materials and Utilities Consumption
1) Ammonia Plant
The raw material and utilities consumption of ammonia plant is summarized
below for before revamp, after energy saving and after feedstock conversion.
as per ton ammonia
before revamp after energy saving after feedstock change
Feedstock 5.501 5.389 5.611 Gcal
Fuel
Naphtha or NG 3.405 3.215 2.931 Gcal
Steam 0.775 - 0.169 -0.411 Gcal
Power 0.110 0.170 0.166 Gcal
C.W 0.293 0.239 0.240 Gcal
subtotal 4.583 3.455 2.926 Gcal
Total 10.084 8.844 8.537 Gcal
Urea Plant
The raw materials and utilities consumption of urea plant is summarized
below in comparison before and after renovation.
Existing Renovated
Steam (T/T)
Import 43.0 Kg/cm2G x 385°C 1.67 1.10
11.4 Kg/cm2G x 215°C 0.09 -
Export 21.5 Kg/cm2G x 318°C - -0.16
11.8 Kg/cm2G x 265°C -0.32 -
Net 1.44 0.94
Electricity (kWh/T)1} 86 77
Energy (Gcal/T)
Steam 1.101 0.717
Electricity 0.211 0.189
Total 1.312 0.906
Saving Base 0.406
- 2 - 69 -
Feedstock (T/T)
ammonia 0.58 0.58
C02 0.74 0.74
Note 2) including power for cooling water
Net steam consumption calculated by subtracting export steam from import
steam decreases by 0.50 T/T, approximately 40% reduction. Electric power
consumption decreases by 9 kWh/T, owing to less power requirement of C02
Compressor and Ammonia Feed Pump. Electric power consumption
includes those in CT-2 and CT-3.
Raw materials consumption, such as ammonia and C02 is principally
maintained same as before process renovation.
Energy consumption is calculated for evaluation purpose from 0 °C water-
based steam enthalpy and electric power. To convert electric power to
energy, 2,457 kcal/kWh is used considering thermal efficiency of ordinary
power plant.
The energy consumption of urea plant is reduced from 1.312 Gcal/T to 0.906
Gcal/T, thus 0.406 Gcal/T energy is saved.
- 2 - 70 -
2.2.5 Scope of Supply
It is presumed that the EPC project execution will be performed based on LSTK
contract, however, ZIL will be deeply involved in the course of project
implementation and in the plant operation stage after completion of the plant
construction. Scope of works both for Japan and India side are described as below,
keeping the flow of project implementation in order.
Work Item India side Japan side
F/S by Japan side(this feasibility study) Support Execute
Evaluation on the above F/S by India side Execute Support*1
Priority ranking of projects in India Execute Support*1
Detailed F/S by India side Execute Support*1
Discussion on CDM conditions Execute Support*1
Request for Japanese fund*4 Execute Support*1
Environment Impact Assessment Execute Support*1
Statutory Approval Execute Support*1
Procurement of equity fund Execute -
Evaluation of the project by Japanese agency Support Execute*2
Execution of Loan Agreement Execute Execute*2
Selection of EPC contractor Execute -
EPC Contract(refer to *3 for details) Execute -
Pre-commissioning and Commissioning Execute'3 -
(Trade-off of C02 emission right) (Execute) (Support)
Commercial Operation Execute -
Note: M Toyo will support as a follow up of this F/S, if necessary.
*2 Japanese gavermental agency will execute.
*3 It is presumed that EPC project execution will be performed based on
LSTK contract, thus all equipment and materilas required for the plant
facilities are included in the scope of EPC contractor. Further details are
-2 - 71 -
defined as below.
1) Equipment and Materials
The following equipment and materials required for the construction of
the plant facilities are included in the scope of supply of EPC contractor.
(a) All itemized equipment
(b) All materials for piping, electrical, instrument and fire protection
(c) Catalyst and chemicals
(d) 2 years operation spare parts
2) Service
The following services are included in the scope of EPC contractor.
(a) Basic design and detailed engunering
(b) Procurement service, inspection, expediting and transportation of
equipment and materials
(c) Civil and building works
(d) Erection and assembly works
(e) Commissioning Supervision
The following services are, however, are included in the scope of
India side.
(a) Demolition and relocation of the existing facilities
(b) Works to get government approval
(c) Operation and maintenance of the plant
3) Fund
Amomg the fund required fot implementation of the project, foreign
currenvy portion will be by Japan side, while local currency portion will
be by India side. Refer to Chapter 4 for the exact amount of each portion. *
*4 Request for Japanese fund would be executed after agreed in the
international conference on CDM.
-2-12-
2.2.6 Condition and Issues for Project Execution
The following presumptions are made for implementation of the project:
a) Required fund is procured under the presumption that 66.9 % of total
investment cost is by Japanese fund and the remainder 33.1 % is by equity.
b) All of gas emissions, liquid wastes, solid wastes and noise which will be
generated from the project facilities are within the limitation of environment
control sepecifications. There is no damage to ecological balance of the
region.
c) All equipment and materials for the plant facilities can be delivered to the
plantsite without any restrictions. Also, all materials and services for the
project are not subject to the restriction by import and export control.
d) There is neither ancient monument nor treasure trove in the candidate plant
site.
It can be said from the site survey conducted during the period of this study that
items b), c) and d) listed above would be resolved in the course of project
implementation. For Item a) the request for Japanese fund would be executed
after agreed in the international conference on CDM.
2.2.7 Project Execution Schedule
Project execution schedule is planned as follows.
Work Item
F/S by Japan side(this feasibility study)
Evaluation on the above F/S
Application of Japanese fund
Preparation of equity raising
Environment Impact Assessment
Selection of EPC contractor
Start of EPC works
Basic design
Schedule
Sep. 2000 — Mar. 2001
Apr. 2001 — Sep. 2001
Oct. 2001 - Jan. 2002
Nov. 2001 - Feb. 2002
Dec. 2001 — Jan. 2002
Dec. 2001 - Feb. 2002
Mar. 2002
Mar. 2002 - Oct. 2002
Duration(month)
7
6
4
4
2
3
8
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Statutory approval Apr. 2002 — Aug. 2002 5
Detailed engineering May, 2002 — Feb. 2003 10
Procurement of equipment & materials Jul. 2002 — Oct. 2003 16
Construction of the plant Feb. 2003 — Mar. 2004 14
1st Tie-in May, 2003 1
2nd Tie-in May, 2004 - Jul. 2004 3
Pre-commissiong/commissioning Aug. 2004 — Sep. 2004 2
Start of commercial operation Oct. 1st, 2004 —
Note M Request for Japanese fund would be executed after agreed in the
international conference on CDM.
-2-74-
2.3 Financing Plan
2.3.1 Financing Plan for Project Execution
(1) Required Fund
Required fund as Total Investment Cost is 60,832 MUSS, breakdown of which is
summarized below:
(UNIT: M US$)
ITEM ForeignCurrency
LocalCurrency Total
Erection Cost 40,678 18,200 58,877
Pre-production Cost 0 0 0
Initial Working Capital 0 0 0
Interest during Construction 0 1,954 1,954
Total Investment Cost 40,678 20,154 60,832
(2) Debt/Equity Ratio
Considering the nature of the Project (this project is oriented for environment
measure and revamping of the existing plant, therefore, timing of implementation is
the most important) and the difficulty & high charge for foreign exchange
procurement in India, debt portion is planned to be maximized within a limitation
of finance amount of Japanese fund like Export Credit. For the evaluation of
profitability in this F/S, it is assumed that debt / equity ratio for required funds
would be procured from Export Credit of Japan Bank for International Corporation
(“JBIC”) and the ratio of debt would be maximized upto the limitation of the export
credit, i.e. 85% of the foreign currency portion of the contract price and for local
currecy portion, the same amount as the down payment of foreign currency portion:
- Debt 40,678 MUSS (66.9 %)
- Equity 20,154 MUSS (33.1 %)
(3) Financing Plan
Considering the difficulty of procurement of forcing currency (in terms of time and
capacity) and high charge in India, the most prefarable finance for the realization of
- 2 - 75 -
the project is assumed to use the export credit to be provided by JBIC, especially
“Supplier’s Credit”.
The credit condition of “Supplier’s Credit” is one of the most advantageous finance
facilities which can be applied to India. The typical terms and conditions of
“Supplier’s Credit” is as follows:
Lender Japan Bank for International Corporation (JBIC)
and Commercial Banks (co-financing lenders) in
Japan
Borrower : Zuari Industries Limited (through Japanese
Company)
Finance Amount : 85% of the foreign currency portion of the contract
price for local currecy portion, the same amount as
the down payment of foreign currency portion
Interest Rate : CIRR (1.85% per annum for Japanese Yen as of
February 2001)
Repayment period : 10 years from 6 months after plant acceptance,
every six months, 20 times
Procurement condition More than 30% of Japanese Contents (hard & soft
portion)
Payment Security : Guarantee issued by Government or first class
local bank
The typical procedure of “Supplier’s Credit” is described as follows:
1) The outline and contract condition of the project shall be recognized by JBIC for
the project of Supplier’s Credit (to be explained by borrower from JBIC i.e.
Japanese Company). Japanese Company will find Commercial Banks (co
financing lenders) in parallel.
2) Before the contract conclusion between Indian Client and Japanese Company,
the final condition of the contract should be approved by JBIC.
3) After the contract conclusion between Indian Client and Japanese Company,
Japanese Company will proceed with application to JBIC for "Supplier’s
Credit”.
- 2 - 76 -
4) Loan Agreement will be concluded between JBIC and Japanese Company and
Japanese Company will borrow the money as per the progress of the project and
lend the same to Indian Client.
2.3.2 Conceptual Financing Plan
The total investment cost is estimated as 60,832 MUS$ with debt of 40,678
MUSS and equity of 20,154 MUSS. As described in section 2.2.3, Zuari
Industries Ltd. has gained the profit since its foundation of 1967 (in only 1999,
they lost due to special and unexpected reason) and it is expected that there are no
difficulties for the repayment of loan and procurement of capital is possible. Zuari
Industries Ltd. is one of leading companies of second largest financial combine
“Birla Group” in India and Zuari Industries Ltd. itself is diversificated to various
business field such as cement and therefore, has stable business foundation.
Also, the existing plant of Zuari Industries Ltd. was built with financial support of
former OECF in Japan and the repayment of the same is settled without any
problems. Furthermore, another fertilizer company of Birla Group i.e. Chambal
Fertilisers and Chemicals Ltd. built a fertilizer plant with utilizing former J-
EXIM’s Supplier’s Credit in 1999 and the repayment is smoothly being done.
Therefore, it can be said that Zuari Industries Ltd. has deep and broad knowledge
of Export Credit.
In the meantime, foreign exchange reservation of India is stablly increased with
following tendency:
March 1999 3,123 Million USD
March 2000 5,546 Million USD
-2-11 -
2.4 Conditions for Clean Development Mechanism (CDM)
2.4.1 Coordination Issues for Project Materialization
Coordination issues to be solved for the project materialization are described
below.
(1) Trade-off of C02 Emission Right
Zuari Industries Limited fully understands that this project is well suitable for
needs of CDM. Discussions were not made on trade-off issues of C02
emission right in the course of this feasibility study. Further discussions and
negotiations would be made in line with the conclusions that would be
determined in the international conference.
(2) Coodination Issue for CDM Condtion
Based on the presumption that this project be collaboratively inplemented
under CDM by Japan as develpoped country and India as developing country,
further discussions would be made between both governments as well as
between Toyo Engineering Corporation and Zuari Industries Limited, in order
to finalize the project scope and to define the scope of woks.
2.4.2 Possibility that India consents to apply CDM
The government of India is presently considering the guideline of fertilizer subsidy
policy with 3 steps reducing amount of subsidy in order to minimize financial
deficit due to increase of subsidy and to recover competitiveness of fertilizer
production cost considering the affiliation to WTO. The feedstock change and
energy saving incorporated in this project is fully in accordance with the long term
policy on the fertilizer sector under consieration by the government of India.
Zuari Industries Limited (ZIL) is a private corporation, but it is carrying out its
business activities in line with the government fertilizer policy. ZIL is, thus, in
position to make positive efforts to follow the decisions made by the Government
of India.
- 2 - 78 -
CDM is to aim to reduce the greenhouse performance gasses through such projects
as to be collaboratively executed between developed and developing countries, and
therefore, India could probabry consent to apply CDM.
- 2 - 79 -
CHAPTER 3
EFFECTS OF PROJECT
Summary: Effects achievable by implementation of the project such as energy saving and greenhouse performance gas reduction were examined through quantitative evaluation and estimation before and after project implementation. Reduction of the greenhouse performance gas was evaluated with a focus on the quantity of C02 gas reduction. In addition, discussions were made on the methods for review and confirmation of effects.
CHAPTER 3 EFFECTS OF PROJECT
3.1 Effects on Energy Saving
3.1.1 T echnical Background
Zuari Industries Limited (ZIL) produces ammonia by using naphtha as feedstock and a large
quantity of fuel. Feedstock naphtha is mixed with steam and converted into hydrogen after
reformed at about 800 deg C. Then air is introduced and reformed further at about 1000
deg C. Carbon monoxide (CO) produced in steam reforming is converted to hydrogen by
the shift reaction. Then carbon dioxide (CO?) simultaneously produced is removed and the
removed carbon dioxide is used as a feedstock in urea plant. The synthesis gas after CO?
removed is further purified by complete removal of carbon oxides and pressurized in a
compressor. The pressurized synthesis gas is fed to an ammonia converter to produce
ammonia.
In ammonia process reaction occurs in each section at high temperature. Reaction
conversion and heat recovery from high temperature effluent stream are very important. In
ammonia process a large quantity of energy is consumed. Reforming of naphtha feedstock
consumes a large quantity of steam and C02 removal consumes heat to regenerate C02.
High pressure compressor also consumes a large quantity of steam.
Energy saving technologies are applied in the project to reduce energy required in CO?
removal, high pressure ammonia synthesis and steam turbines.
The major applied technologies are listed below.
1) aMDEA process for C02 removal
The solution of aMDEA process has a characteristic of chemical and physical absorption
compared with the existing process. Absorbed C02 is partially released by flashing in the
intermediate stage. Therefore required heat for regeneration can be reduced.
2) KAAP converter installed in ammonia synthesis
Although the existing ammonia converter uses iron catalyst, but KAAP converter at the
downstream uses ruthenium catalyst which is more active by 20-30 times than iron
catalyst. Therefore the outlet ammonia content of KAAP convertor can be increased and
the circulation rate of synthesis loop can be reduced. Accordingly the required power of
synthesis gas compressor and refrigerator can be reduced.
3) High pressure condensate stripper
The process condensate of the existing plant is flashed at atmosphere pressure. So energy
-3-1-
loss exists due to vapor loss. In the revamp project the process condensate is stripped by
steam in a high pressure condensate stripper and the stripped vapor is recycled to primary
reformer without energy loss. Carbon dioxide, methanol and ammonia contained in the
stripped vapor is decomposed in the primary reformer without venting to atmosphere.
4) Modification of compressors and turbines
The internals of synthesis gas compressor, its turbine and refrigerant compressor will be
modified to improve efficiency. The modification plans were studied by manufacturers.
Urea is produced with ammonia and C02 supplied from ammonia plant Urea synthesis
reaction occurs at high temperature and high pressure and consumes a large quantity of
power and steam. The total steam consumption has been reduced by the improvement of
process. TEC's ACES 21 process featuring improvement of reaction efficiency and
effective recovery of heat is applied to the existing urea plant to reduce energy effectively
and economically. ACES 21 applies a stripper and a condenser to increase conversion of
urea reaction. Effluent from a urea reactor is stripped by C02 and unreacted materials is
recovered in a condenser and recycled to a urea reactor. A heat exchanging device is
provided in a stripper and a condenser to increase energy efficiency.
Energy saving is also achieved by feedstock conversion from naphtha to natural gas in the
ammonia plant
3.1.2 Baseline
If the project should not be materialized, the operating status would be assumed same as last
year (2000). Accordingly the actual operating data in 2000 is applied as the baseline of
energy consumption in the ammonia and urea plants.
The ammonia plant uses naphtha for feedstock and fuel and generated steam is exported to
the outside (urea and/or utility) after effective heat recovery. In case of shortage of steam in
the plant steam is imported from the outside.
The energy consumption in the ammonia plant is calculated as total energy consumption of
feedstock and fuel as low heat value basis, minus export steam as enthalpy basis, plus import
steam as enthalpy basis. Power consumption and cooling water consumption are added to
the above total energy consumption after converted into energy basis.
The urea plant uses steam, power and cooling water. The energy consumption in the urea
plant is calculated as total energy consumption of import steam as enthalpy basis, minus
-3-2-
export steam as enthalpy basis. Power consumption and cooling water consumption are
added to the above total energy consumption after converted into energy basis.
Baseline of energy consumption in the ammonia and urea plants of ZIL is specified as
follows, based on the actual operating data in 2000.
Ammonia Urea
Energy consumption 10.084 Gcal 1.312 Gcal
per ton-product
Production capacity 750 tons 1,300 tons
per day
The above energy consumption is converted to crude oil consumption using 10,000 kcal/kg
as below.
Ammonia Urea
Crude oil consumption 1,008.4 kg 131.2 kg
per ton-product
Production capacity 750 tons 1,300 tons
per day Total
Annual crude oil consumption
Note: 330 days per year
249,579 toe/y 56,285 toe/y 305,864 toe/y
Quantitative Effects
Energy saving technologies applied in the ammonia and urea plants can reduce energy.
The feedstock change in the ammonia plant can also reduce energy and C02 emission
1) Quantity of Energy Saving
1-1) Ammonia plant
(a) by energy saving technologies
Baseline after energy saving
Production capacity per day 750 tons 750 tons
Feedstock and fuel naphtha naphtha
Energy consumption per ton 10.084 Gcal 8.844 Gcal
-3-3-
Annual energy saving = 750 x (10.084 - 8.844) x 330 = 306,900 Gcal
(b) by feedstock change
after energy saving after feedstock change
Production capacity per day 750 tons 750 tons
Feedstock and fuel naphtha natural gas
Energy consumption per ton 8.844 Gcal 8.537 Gcal
Annual energy saving = 750 x (8. 844 - 8.537) x 330 = 75,983 Gcal
1-2) Urea plant
(a) by energy saving technologies
Baseline after energy saving
Production capacity per day 1,300 tons 1,300 tons
Energy consumption per ton 1.312 Gcal 0.906 Gcal
Annual energy saving = 1,300 x (1.312-0.906) x 330 = 174,174 Gcal
1-3) Total of Ammonia and Urea plants
Annual energy saving = 306,900 + 75,983 + 174,174 = 557,057 Gcal
The above energy saving figures are converted to crude oil equivalent using 10,000
kcal/kg as below.
1-4) Ammonia plant (energy saving and feedstock change)
Annual reduction of crude oil = 30,690 + 7,598 = 38,288 toe/y
1-5) Urea plant (energy saving)
Annual reduction of crude oil = 17,417 toe/y
1-6) Total of Ammonia and Urea plants
Annual reduction of crude oil = 38,288 + 17,417 = 55,705 toe/y
2) Total Energy Saving for Project Life
Total quantity of the energy saving over the project life is 1,114,100 toe crude oil
-3-4-
equivalent as summarized below.
Total Quantity of Energy Saving
Period, Year Crude oil equivalent, toe/y Total Energy saving, toe
1* to 10th 55,705 557,050
11th to 20th 55,705 557,050
Total 1,114,100
3.1.4 Review and Confirmation
Effect on energy saving after implementation of the Project is planned to measure with
following provisions.
1) Row measurement devices (ordinary flow meter can be applied) will be installed on all
feed gas lines, which enables to determine the exact quantity of total feedstock and fuel.
2) Row measurement devices will be installed on all export and import lines such as steam
to measure the exact quantity of the respective stream.
3) Row measurement devices will be installed on all product streams such as ammonia and
urea.
4) Composition analysis on feedstock and fuel will be performed, which enable to calculate
and confirm the heating value of the respective stream.
5) Electric power consumption will be measured and monitored by kW meter.
6) Row measurement devices will be installed on cooling water circulation lines.
7) All of above flow rate and electric power consumption measurements are continuously
monitored and recorded, while composition analysis on process streams and feedstock
and fuel are performed periodically, for example, once per month.
-3-5-
3.2 Reduction of Greenhouse Performance Gas
3.2.1 Technical Background
Zuari Industries Limited (ZIL) produces ammonia by using naphtha as feedstock and a large
quantity of fuel. Feedstock naphtha is mixed with steam and converted into hydrogen after
reformer and carbon dioxide is produced by the shift reaction. Most of C02 is used as a
feedstock in the urea plant, but the balanced C02 is vented to the atmosphere.
A big amount of Carbon Dioxide (C02) as the greenhouse performance gas is generated as a
result of combustion of fuel to supply the energy in the ammonia and urea plants.
Feedstock change from naphtha to natural gas in the ammonia plant can reduce COa
generation on reforming and shift reaction and all C02 is used as a feedstock in the urea plant
So no C02 is vented to the atmosphere. Natural gas feedstock can also reduce energy
consumption in the ammonia plant.
In addition to Carbon Dioxide, there is possibility to discharge Nitrogen Oxide (N20, NO,
NOx, etc.) as the potential greenhouse performance gas, but these gasses are not included in
the evaluation of effects on greenhouse performance gases due to the reason that quantities
of these gasses are very small compared to that of Carbon Dioxide (C02).
3.2.2 Baseline
If the project should not be materialized, the operating status would be assumed same as last
year (2000). Accordingly the actual operating data in 2000 is applied as the baseline of
Greenhouse Performance Gas in the ammonia and urea plants.
The ammonia plant uses naphtha for feedstock and fuel and generated steam is exported to
the outside (urea and/or utility) after effective heat recovery. In case of shortage of steam in
the plant steam is imported from the outside.
The energy consumption in the ammonia plant is calculated as total energy consumption of
feedstock and fuel as low heat value basis, minus export steam as enthalpy basis, plus import
steam as enthalpy basis. Power consumption and cooling water consumption are added to
the above total energy consumption after converted into energy basis.
The urea plant uses steam, power and cooling water. The energy consumption in the urea
plant is calculated as total energy consumption of import steam as enthalpy basis, minus
export steam as enthalpy basis. Power consumption and cooling water consumption are
added to the above total energy consumption after converted into energy basis.
-3-6-
Energy consumption in the ammonia plant consists of feedstock and fuel. Fuel will be
reduced with energy saving. After feedstock change from naphtha to natural gas C02
produced in the process will be reduced and energy consumption will be also reduced
Baseline of Greenhouse Performance Gas in the ammonia and urea plants of ZIL is specified
as follows, based on the actual operating data in 2000.
1) C02 generation by fuel consumption in the ammonia plant
Among total energy consumption of 10.084 Gcal/ton, 4.583 Gcal/ton corresponds to
fuel.
Annual energy consumption as fuel = 750 x 4.583 x 330 = 1,134,293 Gcal
Crude oil equivalent = 113,429 toe/y (@10,000 kcal/kg)
Annual C02 generation =
113,429/1000 x 42.62 x 20 x 0.99 x 44/12 = 350,973 t-CO^y
2) C02 generation by feedstock in the ammonia plant
Daily produced C02 in the ammonia process is estimated 1,157 t-COyd based on the
simulation of 750 t/d capacity.
Annual C02 generation in the ammonia plant =1,157 x 330 =381,810 toe/y
3) C02 generation by fuel consumption in the urea plant
Annual energy consumption as fuel = 1,300 x 1.312 x 330 = 562,848 Gcal
Crude oil equivalent = 56,285 toe/y (@10,000 kcal/kg)
Annual C02 generation =
56,285/1000 x 42.62 x 20 x 0.99 x 44/12 = 174,158 t-COyy
4) C02 consumption as feedstock in the urea plant
C02 consumption is 0.74 t-COyt-urea.
Annual C02 consumption as feedstock in the urea plant base on 1,300 t/d capacity.
Annual C02 consumption = 1,300 x 0.74 x 330 =317,460 t-COyy
5) Total of Ammonia and Urea plants
Annual C02 generation =
350,973 + 381,810 + 174J '8 - 317,460 = 589,481 t-COyy
-3-7-
3.2.3 Quantitative Effects
Energy saving technologies applied in the ammonia and urea plants can reduce C02. The
feedstock change in the ammonia plant can also reduce C02.
1) Reduction of C02 by energy saving in the ammonia and urea plants
(a) Ammonia plant
Baseline
Production capacity per day 750 tons
Feedstock and fuel naphtha
Fuel consumption per ton 4.583 Gcal
after energy-saving
750 tons
naphtha
3.455 Gcal
Annual energy saving = 750 x (4.583 - 3.455) x 330 = 279,180 Gcal
Annual reduction of crude oil equivalent 27,918 toe/y
Annual C02 reduction
27,918/1000 x 42.62 x 20 x 0.99 x 44/12 = 86,384 t-CO^y
(b) Urea plant
Baseline
Production capacity per day 1,300 tons
Energy consumption per ton 1.312 Gcal
after energy saving
1,300 tons
0.906 Gcal
Annual energy saving = 1,300 x (1.312-0.906) x 330 = 174,174 Gcal
Annual reduction of crude oil equivalent 17,417 toe/y
Annual C02 reduction
17,417/1000 x 42.62 x 20 x 0.99 x 44/12 = 53,892 t-COVy
(c) Total of Ammonia and Urea plants
Annual C02 reduction = 86,384 + 53,892 = 140,276 t-CO^y
2) Reduction of C02 by feedstock change in the ammonia plant
by energy saving
after energy .saving afteiieedstock change
Production capacity per day 750 tons 750 tons
Feedstock and fuel naphtha natural gas
Fuel consumption per ton 3.455 Gcal 2.926 Gcal
-3-8-
Annual energy saving = 750 x (3.455 - 2.926) x 330 = 130,928 Gcal
Annual reduction of crude oil equivalent 13,093 toe/y
Annual C02 reduction
13,093/1000 x 42.62 x 20 x 0.99 x 44/12 = 40,513 t-CCVy
(b) C02 reduction in the process
before feedstock change after feedstock change
Production capacity per day 750 tons 750 tons
Feedstock and fuel naphtha natural gas
C02 generation by feedstock 1157 t-CCX/d 962 t-COyd
C02 consumption in urea 962 t-COyd 962 t-COyd
C02 vent to atmosphere 195 t-COyd 0 t-COyd
Annual C02 reduction 195 x 330 = 64,350 t-CCVy
(c) Total C02 reduction in the ammonia plant by feedstock change
Annual C02 reduction = 40,513 + 64,350 = 104,863 t-COyy
3) Total C02 reduction
Annual reduction of C02 = 140,276 + 104,863 = 245,139 t-CCVy
4) Total C02 reduction for Project Life
Total quantity of the C02 reduction over the project life is 4,902,780 t-C02 as
summarized below.
Total Quantity of C02 Reduction
Period, Year C02 Reduction, t-CCVy Total C02 Reduction, t-C02
1st to 10th 245,139 2,451,390
11th to 20th 245,139 2,451,390
Total 4,902,780
-3-9-
3.2.4 Review and Confirmation
Effect on the reduction of C02 gas by the implementation of the Project is planned to review
and confirm by the following provisions and methods.
1) Flow measurement devices (ordinary flow meter can be applied) will be installed on all
feed gas lines, which enables to determine the exact quantity of total feedstock and fuel.
2) Flow measurement devices will be installed on all export and import lines such as steam
to measure the exact quantity of the respective stream.
3) Flow measurement devices will be installed on all product streams such as ammonia and
urea and C02 vent line.
4) Composition analysis on feedstock and fuel will be performed, which enable to calculate
and confirm the heating value of the respective stream.
5) Electric power consumption will be measured and monitored by kW meter.
6) Flow measurement devices will be installed on cooling water circulation lines.
7) All of above flow rate and electric power consumption measurements are continuously
monitored and recorded, while composition analysis on process streams and feedstock
and fuel are performed periodically, for example, once per month.
8) Reduction of C02 as greenhouse performance gas can be calculated based on the
measured flow and composition of feed gasses and products, and utilities consumption.
- 3 -10 -
3.3 Affects to Productivity
The ammonia and urea plants of ZIL have many experiences of more production than design
capacity for the project. In this F/S 10 % capacity allowance for production of ammonia
and urea was incorporated in the design in accordance with ZIL's request. So there will be
a flexibility in productivity.
If another 10 % capacity allowance (total 20%) is required, additional equipment should be
designed with 20 % allowance, but total investment cost will be increased The design
basis should be discussed in the stage of project execution with ZIL.
-3 -11 -
CHAPTER 4
PROFITABILITY
Summary: Evaluation basis such as required fund (erection cost, pre-production cost, initial working capital and interest during construction), operation plan (production plan, sales plan, required number of employee, production cost, and so on), construction schedule, project life and taxation system were estimated and established in order to analyze the project profitability. Further evaluation was made through sensibility studies on FIRR against the key project values.
CHAPTER 4 PROFITABILITY
4.1 F inancial Evaluation
4.1.1 Evaluation Method
(1) Without Case (Revamping Project is not implemented)
Ammonia and Urea plants of Zuari Industries Ltd (ZIL) are under operation and the
project in this feasibility study is revanping one for the those existing plants. In case that
the project is not implemented, it is assumed that the existing ammonia and urea plants
continue to their operation for producing 750 T/D ammonia and 1300 T/D urea. The
econmic study of "Without Case” is conducted based on expected sales revenue and
production cost, and actual depreciation amount of the existing facilities and debts.
Financial statements and cashflow for whole project life of 3 years poiject construction
period and 20 years operation period are made based on above and economic status are
evaluated.
ZIL produces ammonia form naphtha in the existing ammonia plant and the final product
urea are produced from ammonia and by-product of de-carbonate supplied from the
ammonia plant ZIL also produces compund fertilizer such as NPK and DAP by using
ammonia and urea. In this feasibility study, only cost for producing final prosuct of urea
are evaluated. The study is conducted only for ammonia and urea production facilities.
(2) With Case (Revamping Project is implemented)
In case that the project is implemented, additional cost for the revamping proejct and
improved production cost are taken into consideration for “With Case”. The econmic study
of “With Case” is conducted in the same manner of above “Without Case”. Financial
statements and cashflow for whole project life of 3 years poiject construction period and 20
years operation period are made based on above and economic status are evaluated
(3) Evaluation of Revamping Projec
For measuring contribution of the revamping project, differences of profit / loss between
“With Case” and “Without Case” are calculated Evaluation of the project is analysed
-4-1-
4.1.2
(1)
based on those differences of profit / loss against investment cost for the project. The
differences of increment "With Case" minus “Without Case" is defined as “With -
Without Case".
Required Fund
Basic Conditions of Calculation
1) Currency Rates
The following currency rates are applied to this study based on the rates as of January
31% 2001.
1.00 US$ =105.00 JPY = 47 Rupees
US$ currency is basically used in this report
2) Escalation Rates
No escalation for any cost and price up to and after the commercial operation start is
applied to this study.
(a) Foreign Currency Portion
- up to the commercial operation start 0.00 %/year
- after the commercial operation start 0.00 %/year
(b) Local Currency Portion (Rupee Portion)
- up to the commercial operation start 0.00 %/year
- after the commercial operation start 0.00 %/year
Actually Rupee portion should be considered its price escalaion. But currency used
for this study is US dollars, and escalation for prices of Rupee portion indicated in US
dollars is not taken into account with cosideration of exchange rate between Rupee
and US dollars.
-4-2-
Erection Cost
The erection cost of this revamp project is estimated and summarized as below. The
project facilities are installed inside of the existing ZIL plant area and land aquisitioncoast
is not required Physical coningency for unexpected additional cost requirement is taken
into account as 2.0 % of net erectin cost:
(UNIT: M US$)
ITEM ForeignCurrency
LocalCurrency Total
Land Acquisition Cost 0 0 0
License Fee 1,048 328 1,376
Engineering Fee 7,832 1,572 9,404
Equipment & Material Cost 28,239 10,025 38.264
Transportation Cost (Including above equipment & material cost)
Insurance (Including above equipment & material cost)
Erection & Civil Works 2,761 5,918 8,679Sub total 39,880 7%843
Physical Contingency 798 357 1,153
Price Escalation 0 0 0
Total Erection Cost 40,678 18,200 58,877
The above cos includes all customs duties and taxes in India.
The above cost is assumed to be allocated per following ratio during project construction
period
First year of project construction (-3 year) 20%
Second year (-2 year) 40%
Third year (-1 yer) 40%
Pre-production Cost
Pre-project cost are not taken into account because the project is revamping one and
owner’s existing personnels would work as the project members. Training for the
operators/maintenance staff are not required Materials for pre-commissioning and test
opeartion would be very small and could be negrected
Pre-production cost of the project is estimated and summarized as below:
(UNIT: MUSS)
ITEM ForeignCurrency
LocalCurrency Total
Project Management Cost 0 0 0
Training Cost 0 0 0
Material Cost 0 0 0
Total Pre-production Cost 0 0 0
(4) Initial Working Capital (Additional Working Capital)
Additional working capital for the project is taken into account as Initial Working Capital.
But urea production amount and its price are not changed aftter the revamping project, and
hence product inventories, account receivable and operating cash are estimated unchanged
With change of raw materials from naphtha to natural gas, raw material of naphtha of 7
days storage is not required Two years spare pares are included in the erection cost They
are summarized as below:
(UNIT: M US$)
ITEM ForeignCurrency
LocalCurrency Total
Product Inventories 0 0 0
Material Inventories 0 -1,490 -1,490
Account Receivable 0 0 0
Operating Cash 0 0 0
Account Payable 0 0 0
2 years Spare Parts 0 0 0
Total Initial Working Capital 0 -1,490 -1,490
The above reduction of working capital is not evaluated as reduction of initial investment
cost for the revamping poiject and is assumed to contribute to cash balance.
(5) Interest during Construction
Interest during construction will be calculated to be 1,954 MUS$ based on the annual
interest of 7.00 % on foreign curency.
(6) Total Investment Cost
-4-4-
1) Total Investment Cost
Total investment cost of the project is estimated and summarized below:
(UNIT: M US$)
ITEM ForeignCurrency
LocalCurrency Total
Erection Cost 40,678 18,200 58,878Pre-production Cost 0 0 0
Initial Working Capital 0 0 0
Interest during Construction 0 1,954 1,954
Total Investment Cost 40,678 20,154 60,832
2) Required Finance Plan
The required finance plan for the project is presumed as follows:
Total Investment Cost
Foreign Currency Portion
Local Currency Portion
Debt
Equity
60,823 MUSS (100 %)
40,678 MUSS (66.9%)
20,154 MUSS (33.1%)
40,678 MUSS (66.9%)
20,154 MUSS (33.1%)
-4-5-
4.1.3 Operation of Plant
(1) Production and Sales Plan
Productions and sales plans of products during the project life are shown in Table 4.1-1
Production and Sales Plan.
Without Case Table 4.1-1 (1)
With Case Table 4.1-1 (2)
1) Production Schedule
(a) Annual operations days 330 days/year
(b) Commercial Operation Load
Project year Without Case With Case
- 3rd through -1st year 100% 100%
1st year 100% 80%
2nd through 20th year 100% 100%
(c) Production Rate at 100% load
Product Urea (Bagged) 1,300 Ton/Day
(429,000 Ton/Year)
2) Sales Schedule
(a) Sales Amount
Sales schedule of product urea is not changed after the proejct and all product are
assumed to be sold out, because the all produced urea is sold out to domestic market
and production amount is not changed after the project
-4-6-
Table 41-1(1) PRODUCTION AND SALES PLAN FOR WITHOUT CASE MUSS
YEAR 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 TOTAL
UREA (MAIN PRODUCT)
CAPACITY (Ton/Y ear) 429,000 429,000 429,000 429,000 429,000 429,000 429,000 429,000 429,000 429,000 429,000 429,000 429,000 429,000 429.000 429,000 429,000 429,000 429,000 429,000 429,000 429,000 429,000
CAP. VniJ7A'nON(%) 100.0 100.0 100.0 100.0 100.0 100.0 100.0 100.0 100.0 100.0 100.0 100.0 100.0 100.0 100.0 100.0 100.0 100.0 100.0 100.0 100.0 100.0 100.0
PRODUCTION (ToVYrar) 429,000 429,000 429,000 429.000 429,000 429,000 429,000 429,000 429,000 429,000 429,000 429,000 429,000 429,000 429.000 429,000 429,000 429.000 429,000 429,000 429,000 429,000 429,000 9,867,000
INCREASE IN INVENTORY (Ten) 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
SAIT'S VOLUME (ToiVYear) 429,000 429,000 429,000 429.000 429,000 429,000 429.000 429,000 429,000 429,000 429,000 429,000 429,000 429,000 429,000 429,000 429,000 429,000 429,000 429,000 429,000 429,000 429,000 9,867,000
VNIISAITS PRICE(L8$/Ton) 250 250 250 250 250 250 250 250 250 250 250 250 250 250 250 250 250 250 250 250 250 250 250
SALES REVENUE 107,250 107,250 107,250 107,250 107,250 107,250 107.250 107,250 107,250 107,250 107,250 107,250 107,250 107,250 107,250 107,250 107,250 107,250 107,250 107,250 107,250 107,250 107.250 2,466,750
Tabic 4.1-1 (2) PRODUCTION AND SALES PLAN FOR WITH CASE MUSS
YEAR 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 TOTAL
UREA (MAIN PRODUCT)
CAPACITY (Tcn/Year) 429,000 429,000 429,000 429,000 429,000 429,000 429,000 429,000 429,000 429,000 429,000 429,000 429,000 429,000 429,000 429,000 429,000 429,000 429,000 429,000 429,000 429,000 429,000
CAP. UTILIZATION (%) 100.0 100.0 100.0 80.0 100.0 100.0 100.0 100.0 100.0 100.0 100.0 100.0 100.0 100.0 100.0 100.0 100.0 100.0 100.0 100.0 100.0 100.0 100.0
PRODUCTION (Ton/Year) 429,000 429,000 429,000 343,200 429,000 429,000 429,000 429,000 429,000 429,000 429,000 429,000 429,000 429,000 429,000 429,000 429,000 429,000 429,000 429,000 429,000 429,000 429,000 9,781,200
INCREASE IN INVENTORY (Ton) 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
SALES VOLUME (TorVYear) 429,000 429.000 429,000 343,200 429,000 429,000 429,000 429,000 429,000 429,000 429,000 429,000 429,000 429,000 429,000 429,000 429,000 429,000 429,000 429,000 429,000 429,000 429,000 9,781,200
UNITS AUS PRICE (LSVTon) 250 250 250 250 250 250 250 250 250 250 250 250 250 250 250 250 250 250 250 250 250 250 250
SAIES REVENUE 107,250 107,250 107,250 85,800 107,250 107,250 107,250 107,250 107.250 107,250 107,250 107,250 107,250 107,250 107,250 107,250 107,250 107,250 107,250 107,250 107,250 107,250 107,250 2445,300
(b) Sales Prices
i) Urea farmer gate price in India is very much lower than the international market
price level which is decised by the Indian Government. But the urea production
cost in India is higher than the same of international price. The gap between
farmer gate price and production cost is compensated by the Governmental
subsidy and fertilizer production company could get profit based on the subsidy.
Now Government of India decided to reduce this subsidy and decleared to stop
the subsidy by the year of 2006. Hence it is impossible to evaluate the proejct
based on farmer gate price.
It is reported that Indian urea production cost in 1999 was US$/Ton 200 - 250.
The cost varies very widely depending on naphtha price. The current naphtha
price also fluctuated widely according to crude oil prices and it is now high price
level.
In this study sales price is assumed at US$/Ton 250 and sensitivity analysis on
urea price is conducted between US$/Ton 150 - 300.
ii) The all sales prices are not applied to the escalation for whole proj ect life.
(2) Required Number of Employees
The project is revamping project and no additional employees is required
(3) Training Plan
The operation and maintenance stuff in the existing ZIL ammonia and urea plants have
enough knowledge and capability. The newly introduced technology does not need special
training for such stuff. It is judged that training for the project can be carried out during pre
commissioning and intital commissioning period
(4) Recruiting Plan
The project is revamping project and no additional employees is required No recruiting
plan is required
-4-9-
(5) Variable and Direct Fixed Cost
Variable and Direct Fixed Cost during the project life is shown in Table 4.1-2 Variable
Cost and Table 4.1-3 Direct Fixed Cost, which consists of the items listed below.
1) Variable Cost
(a) Raw Material Cost
(b) Urea bag cost and bagging cost
(c) Utility Cost
(d) Catalyst and Chemical Cost
2) Direct Fixed Cost
(a) Labor Cost
Based on the lates actual cost in the existing ammonia and urea plants, labor cost
is assumed at 92 personnel with 24,730 US$ of average annual wage. The same
cost is applied for the cost for With Case.
(b) Factory Overhead Cost
Assumed at 78 % of the labor cost
(c) Maintenance Cost
For Without Case, annual maintenance cost is assumed at US$ 2,241 thousands
according to the existing plant actual cost For With Case, 1.5 % of erection cost
of the project is added on the above annual maintenace cost
ZIL plans replacement of Urea Reactor soon, and in the study the following cost
is assumed as special maintenace cost
Unit: 1,000 US$
Year Without Case With Case
-2nd Year 1,000 1,000
-1* Year 1,500 1,500
Total 2,500 2,500
(d) Tax and Insurance for Fixed Property
Base on the existing plant actual cost, it is assumed at US$/Year 720 thousands.
After revamping project, assumed at 1.79 % of the booked value of foreign
currency of equipment and materials cost is added on the above cost
-4-10-
Table 4.1-2 Variable Cost Summary at 100 % Operation
Items Unit Without Case With Case
Unit price Daily Unit price Daily
(US$) Consumption (US$) Consumption
Naphtha MT 333.43 631.33 333.43 0.00
LNG MMBtu 6.000 0.00 6.000 25,422.62
Bags for Urea Bag 0.267 26,130 0.267 26,130
Catalyst US$/Y 850.09 _ 850.09
Chemicals US$/Y 196.06 _ 196.06
Variable Cost for Bagging MT-Urea 0.281 1,300 0.281 1,300Steam HP(100Kx490°C) Ton 16.943 830 17.706 0
Electricity KWH 0.074 132,148 0.073 140,795
Polished Water M3 0.830 1,335 0.812 1,335
CW Make-up Ton 3.659 9,600 3.659 7,734Steam SH(43Kx385°C) MMKcal 15.251 2,171 15.938 1,430Steam MP(37Kx366°C) Ton 14.771 -107 15.436 -413Steam SM-l(21.5Kx318°C) Ton 13.934 0 14.561 -208Steam SM-2(11.8Kx265°C) Ton 12.757 -416 13.331 0
Steam SM-3(11.8Kx215°C) Ton 12.248 117 12.799 0
Table 4.1-3 Direct Fixed Cost Summary
Items Fixed Cost (US$/Y)
Without Case With Case
Labor Cost for Ammonia & Urea Plants 2,274.8 2,274.8
Factory/Administration & Social Overhead Cost 1,777.8 1,777.8
Maintenance Cost 1,357.7 2,240.9
Tax & Insurance 719.9 1,225.4
Bagging Cost excluding Variable Cost 2,686.8 2,686.8
Sales Expense including Freight 1,190.0 1,190.0
Total 8,709.3 10,097.9
-4-11-
(e) Fixed Cost for Urea Bagging
Base on the existing bagging plant actual cost it is assumed at US$/Year 2,687
thousands. The same rate is applied for With Case.
(6) Production Cost
Production Cost is summarized in Table 4.1-4 Production Cost Statement.
Without Case Table 4.1-4 (1)
With Case Table 4.1-4 (2)
The production cost includes the items listed below.
(a) Variable Cost
(b) Direct Fixed Cost
(c) Depreciation
The amount of depreciation is calculated based on the straight line method.
The un-depreciation amount of the existing plants at the tiem of project start is
assumed at US$ 6,350,000. The same amount is assmued to depreciate for ten years.
The project cost is assumed to depreciate per the following conditions;
Depreciation period 18 years
Residual value 3.16 %
(d) Corporate Tax on Profit
Applied at 38.85 % on Profit
-4-12-
Table 4.1-4(1) PRODUCTION COST (VARIABLE & FIXED DIRECT COST) FOR WITHOUT CASE MUSS
YEAR 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 •IOTAL
VARIAIiLECOST 101.612 101.612 101.612 101.612 101,612 101.612 101.612 101.612 101.612 101.612 101.612 101,612 101.612 101,612 101.612 101.612 101.612 101,612 101.612 101,612 101.612 101.612 101.612 2337,083RAW MA'II'KLAI. 71.769 71.769 71.769 71,769 71.769 71.769 71,769 71.769 71.769 71.769 71.769 71.769 71.769 71.769 71.769 71.769 71.769 71,769 71.769 71.769 71.769 71.769 71.769 1.650689
(4467 69.467 69.467 69.467 69.467 69.467 69,467 69.467 69,467 69.467 69,467 69.467 69,467 69.467 69,467 69.467 69.467 69,467 69,467 69.467 69.467 69,467 69.467 1.597.731LNG 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0Raw Materia) 3 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
2502 2302 2502 2502 2502 2502 2502 2302 2502 2302 2502 2302 2302 2502 2302 2302 2502 2302 2502 2302 2302 2302 2302 52957CATAI.YST & Cl IEMICAI. 787 787 787 787 787 787 787 787 787 787 787 787 787 787 787 787 787 787 787 787 787 787 787 18111
Gtidysl 651 651 651 651 651 651 651 651 651 651 651 651 651 651 651 651 651 651 651 651 651 651 651 14.977136 136 136 136 136 136 136 136 136 136 136 136 136 136 136 136 136 136 136 136 136 136 136 3.134
uiiuiYcosr 29,056 29.056 29.056 29.056 29.056 29,056 29,056 29.056 29,056 29,056 29,056 29,056 29.056 29.056 29,056 29.056 29.056 29.056 29,056 29,056 29.056 29,056 29.056 668283Viuiiililc GtJ for Digging 120 120 120 120 120 120 120 120 120 120 120 120 120 120 120 120 120 120 120 120 120 120 120 2771Su-i.il lll,(IOOKx4<X)) 4.642 4.642 4.642 4,642 4,642 4,642 4,612 4,642 4,642 4.642 4.642 4.642 4,612 4,642 4,612 4.642 4.642 4,6(2 4.6(2 4,642 4.6(2 4,6(2 4,6(2 106771fjeetriiity 3.211 3.211 3.211 3511 3.211 3.211 3.211 3.211 3.211 3.211 3.211 3.211 3.211 3.211 3.211 3.211 3,211 3,211 3.211 3.211 3.211 3,211 3.211 73.859
366 366 366 366 366 366 366 366 366 366 366 366 366 366 366 366 366 366 366 366 366 366 366 8425Raw Wider 0 0 l) 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0CW Make 11590 11590 11590 11590 11590 11590 11590 11.590 11590 11590 11590 11590 11.590 11590 11.590 11.590 11590 11.590 11590 11590 11590 11590 11590 266574Sui.nSIV3K.x3KS) 10.9%; 1092? 10.927 10.927 10.927 10,927 10,927 10927 10927 10927 10927 10927 10927 10927 10927 10927 10927 10927 10927 10927 10927 10927 10927 251510Steitii MP(37Kx366) -521 -52! -521 -523 -523 -523 -523 -523 -523 -523 -523 -523 -523 -523 -523 -523 -523 -523 -523 -523 -523 523 -523 -12024SlinuSM l(215Kx318) 0 0 1) 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0SUi.uSM 2(ll3tK.x265) -1.751 -1.751 1,751 -1.751 -1.751 1.751 -1,751 1.751 1.751 •1,751 -1.751 -1,751 -1.751 -1.751 1.751 -1.751 1.751 -1,751 -1.751 -1.751 -1.751 -1.751 -1.751 -40279Sunn SM-3(1 18Kx215) 473 473 473 473 473 473 473 473 473 473 473 473 473 473 473 473 473 473 473 473 473 473 473 10876Otlut Utility 6 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
dirixtmxeixxxst 8.709 9.709 10,209 8709 8709 8709 8709 8709 8709 8709 8709 8709 8709 8709 8709 8709 8709 8709 8709 8709 8709 8709 8709 202814liJxmrCVfit 2.275 2275 2275 2275 2275 2275 2275 2275 2275 2275 2275 2275 2275 2275 2275 2275 2275 2275 2275 2275 2275 2275 2275 52321S/V Ex]xitriideC<«t 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0I';u1ory OvtdiemlCost 1.670 1.670 1.670 1.670 1.670 1,670 1.670 1,670 1,670 1.670 1.670 1,670 1,670 1.670 1.670 1.670 1,670 1.670 1.670 1,670 1.670 1.670 1.670 38409
U58 2,358 2858 1558 1558 1558 1558 1558 1558 1558 1558 1558 1558 1558 1558 1558 1558 1558 1558 1558 1558 1558 1558 33.728720 720 720 720 720 720 720 720 720 720 720 720 720 720 720 720 720 720 720 720 720 720 720 16559
Iln^igCciG! ix dulilg Vjr'uilllo Cost 2687 2687 2687 2687 2687 2687 2687 2687 2687 2687 2687 2687 2687 2687 2687 2687 2687 2687 2687 2687 2687 2687 2687 61.797
YEAR 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 TOTAL
I'RODUCIIONOE MAIN PRODUCT 429,000 429.000 429.000 429.000 429,000 429.000 429,000 429.000 429.000 429.000 429.000 429.000 429.000 429,000 429.000 429.000 429,000 429,000 429.000 429,000 429,000 429.000 429.000 9.867.000
VARIAI It F. COST 101.612 101.612 101.612 101,612 101.612 101.612 101.612 101.612 101.612 101.612 101.612 101,612 101,612 101,612 101,612 101,612 101.612 101,612 101.612 101,612 101.612 101.612 101,612 2337.083DIRECT HXED COST 8.709 9,709 10209 8709 8709 8709 8709 8709 8709 8709 8709 8709 8709 8709 8709 8709 8709 8709 8709 8709 8709 8709 8709 202814
CASH EACIORY COST 110322 111522 111.822 110522 110522 110522 110522 110322 110322 110322 110322 110322 110322 110322 110322 110322 110322 110322 110322 110322 110322 110,322 110322 2539,897
DEI’RECIAHON 635 635 635 635 635 635 635 635 635 635 0 0 0 0 0 0 0 0 0 0 0 0 0 6350ARMailZAIlON 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
Dlil'RiriA'IlON AND AMOR MZA'IION 635 635 635 635 635 635 635 635 635 635 0 0 0 0 0 0 0 0 0 0 0 0 0 6350
TOI AI-EACIORY COST 110957 111.957 112457 110,957 11(1957 11(1957 110957 110957 110957 110957 110322 110522 110322 110322 110322 110322 110322 110322 110322 110522 110322 110322 110322 2546247
UNflTACIOKY COST(l SS/l'i.i) 259 261 262 259 259 259 259 259 259 259 257 257 257 257 257 257 257 257 257 257 257 257 257
SAITS EXI'ENKIS 1.190 1.190 1.190 1.190 1.190 1.190 1.190 1.190 1,190 1.190 1.190 1,190 1.190 1.190 1.190 1.190 1,190 1.190 1.190 1.190 1.190 1,190 1.190 27.370
Soda) (Xt-rim*) & Hints 10S 108 108 108 108 108 108 108 108 108 108 108 108 108 108 108 108 108 108 108 108 108 108 2480
SAIJiJ (VALUABLEADDED) TAX 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
OI’IKAHNG IXI’liTSIS 112254 113.254 113,754 112254 112254 112254 112254 112254 112254 112254 111.619 111,619 111,619 111.619 111,619 111.619 111.619 111.619 111.619 111,619 111.619 111,619 111,619 2576097
UNflOI'liR.IXriJvKI!(lSJ/li.i) 262 264 265 262 262 262 262 262 262 262 260 260 260 260 260 260 260 260 260 260 260 260 260 6005IN1ER1STON UONGimM 1 186 124 62 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 372INIERU>TONIjONGHJtM2 771 514 257 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 1543lNIERI2>TONLONG'lliRM 3 345 166 83 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 5941NIER1STON LONG TERM 4 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
INIERISTON IjONGIERM D 111 I f 1502 804 402 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 2508
INIERISTONSIIORTIERM Dlilfl 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
TOTAL 1‘KODl CHON COST 113557 114,059 114.157 112254 112254 112254 112254 112254 112254 112254 111.619 111.619 111,619 111.619 111,619 111.619 111,619 111.619 111.619 111.619 111.619 111.619 111,619 2578605UNriT'ROD.COST(tSVIi.i) 265 266 266 262 262 262 262 262 262 262 260 260 260 260 260 260 260 260 260 260 260 260 260
MUSSTable 4.1-4(2) PRODUCTION COST (VARIABLE & FIXED DIRECT COST) FOR WITH CASE
YEAH 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 TOTALVARIAI3IECOS T 101.612 101,612 101,612 57.063 71329 71329 71329 71329 71329 71329 71329 71329 71329 71329 71329 71329 71329 71329 71329 71329 71329 71,329 71329 1,717.149
RAW MA'Il'XIAI, 71.769 71,769 71,769 42111 52639 52639 52639 52639 52639 52639 52639 52639 52639 52639 52639 52639 52639 52639 52639 52639 52639 52639 52639 1.257365Najihtln 69.467 69.4<,7 69,467 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 208400IMG 0 0 0 40269 50337 50337 50337 50337 50337 50337 50337 50337 50337 50337 50337 50337 50337 50337 50337 50337 503.37 50.3.37 50337 996668Raw Malrrial 3 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0Hog 2,302 2302 2302 1.842 2302 2302 2302 2302 2302 2302 2302 2302 2302 2302 2302 2302 2302 2302 2.302 2302 2302 2.302 2302 52497
CATALYST A Cl IHMICA1. 787 787 787 837 1.016 1,016 1,016 1.016 1.016 1,016 1,016 1.016 1,016 1.016 1.016 1.016 1.016 I.OI6 1,016 1.016 1.016 1.016 1,046 23,076Ciinlysl 6.51 651 651 680 850 850 850 850 850 850 850 850 850 850 850 850 850 850 850 850 850 850 850 18785Cliattiatb 1.36 1.36 1.36 157 196 196 196 196 196 196 196 196 196 196 196 196 196 196 196 196 196 196 196 4.291
uni JIY COST 29,056 29,056 29,056 14.115 17,613 17.643 17.643 17,643 17,613 17,643 17.613 17,613 17,643 17,643 17,643 17,643 17,643 17,643 17.613 17,64.3 17,613 17.613 17,61.3 4.36508Variable Cost for Hugging 120 120 120 96 120 120 120 120 120 120 120 120 120 120 120 120 120 120 120 120 120 120 120 2747Slrau IIP(100Kx490) 4,612 4.612 4,612 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 13,927Hcctridly 3,211 3.211 3,211 2729 3,412 3,412 3,412 3,412 3.412 , 3.412 3,412 3,412 3.412 3,412 3,412 3,412 3,412 3,412 3.412 3,412 3,412 3.412 3,412 77,182Polished Water 366 366 366 286 358 358 358 358 358 358 358 358 358 358 358 358 358 358 358 358 358 358 358 8179Raw Wider 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0CW Makoa^i 11.590 11.590 11,590 7.470 9337 9337 9337 9337 9337 9337 9337 9337 9337 9337 9337 9337 9337 9337 9337 9337 9337 9337 9.337 219.650Strau SI l(43Kx385) 10,92.7 10927 10927 6017 7321 7321 7321 7321 7321 7321 7321 7321 7321 7321 7321 7321 7321 7321 7321 7321 7321 7321 7321 181.698S Irani MP(37Kx366) 523 523 523 -1,684 -2105 -2105 -2105 -2105 -2105 -2105 -2105 -2105 2105 -2105 -2105 2105 -2105 -2105 2105 2105 2105 -2105 -2105 43.249Strau SM 1(213Kx3I8) 0 0 0 -800 -999 -999 999 999 999 999 999 999 999 999 999 999 999 999 999 999 999 999 999 19.790Strait SM-2(ll.8K.x265) 1.751 1.751 1.751 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 5.254StraiiSM.XH-8K.x2l5) 473 473 473 0 . o 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 1.419Other Utility 6 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
DIRECT ITXED COST 8,709 9,709 10209 10098 10098 10098 10098 10098 10098 10098 10098 10098 10098 10098 10098 10098 10098 10098 10098 10098 10098 10098 10098 230387IjihnurGnst 2275 2275 2275 2275 2275 2275 2275 2275 2275 2275 2275 2275 2275 2275 2275 2275 2275 2275 2275 2275 2275 2275 2275 52321S/V Exyxitri.'ie Cost 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0Pa<tory Ovdfiral Cost 1.670 1.670 1.670 1,670 1,670 1,670 1,670 1,670 1.670 1,670 1,670 1,670 1,670 1,670 1,670 1,670 1,670 1.670 1,670 1,670 1,670 1,670 1.670 38409Main! (nmcE Cost 1.358 2358 2858 2241 2241 2241 2241 2241 2241 2241 2241 2241 2241 2241 2241 2241 2241 2241 2241 2241 2241 2241 2241 51391Tax & Haunter 720 720 720 1,225 1.225 1,225 1,225 1,225 1.225 1325 1.225 1.225 1325 1,225 1.225 1,225 1,225 1,225 1,225 1,225 1,225 1.225 1,225 26668BogpugCost ex chidingVariable Cc«t 2687 2687 2687 2687 2687 2687 2687 2687 2687 2687 2687 2687 2687 2687 2687 2687 2687 2687 2687 2687 2687 2687 2687 61,797
YEAR 2002 2003 2001 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 TOTALPRODUCTION or MAIN PRODUCT 429,000 429,000 429,000 343,200 429,000 429,000 429.000 429,000 429.000 429,000 429.000 429,000 429.000 429,000 429,000 429,000 429,000 429,000 429,000 429,000 429,000 429,000 429,000 9.781.200
VARIABLE COST 101,612 101,612 101,612 57.063 71329 71329 71329 71329 71329 71329 71329 71329 71329 71329 71329 71329 71329 71329 71329 71329 71329 71329 71329 1,717.149DIRECT FIXED COST 8709 9.709 10,209 10098 10098 10098 10098 10098 10098 10098 10098 10098 10098 10098 10098 10098 10098 10098 10098 10098 10098 10098 10098 230587
CASH FACTORY COST 110322 111322 111.822 67.161 81,427 81,427 81,427 81,427 81,427 81.427 81,427 81.427 81,427 81,427 81,427 81,427 81,427 81,427 81,427 81,427 81.427 81,427 81,427 1,947.736
DLPRIE1AI10N 635 635 635 3,742 3,742 3,742 3,742 3,742 3,742 3,742 3,107 3,107 3,107 3,107 3,107 3,107 3,107 3,107 3.107 3,107 3,107 0 0 62283ARMOTIZATION 0 0 0 391 391 391 391 391 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 1,954
DEPRECIATION AND AM0R I17A110N 635 635 635 4,133 4,133 4,133 4,133 4,133 3.742 3,742 3.107 3,107 3,107 3,107 3.107 3,107 3,107 3,107 3,107 3,107 3,107 0 0 64.237
TOTAL FACTORY COST 110.957 111,957 112457 71,294 85360 85360 85360 85360 85,169 85,169 84334 84334 84334 84334 84334 84334 84334 84.534 84,534 813.34 81334 81,427 81,427 2011.973UNri'FACJORYCQST<LS$/IWi) 259 261 262 208 199 199 199 199 199 199 197 197 197 197 197 197 197 197 197 197 197 190 190
SALES EXTENDS 1.190 1.190 1,190 1.190 1,190 1.190 1,190 1.190 1,190 1,190 1,190 1,190 1,190 1,190 1,190 1,190 1,190 1,190 1,190 1,190 1,190 1.190 1.190 27370Sooal (Xnhtwl & IW»r 108 108 1(8 108 108 108 108 108 108 108 108 108 108 108 108 108 108 108 108 108 108 108 108 2480SAUS (VALUABIE ADDED) TAX 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
OPIKAIINGEXPENSES 112254 113,254 113,754 72392 86858 86858 86858 86858 86467 86467 85,832 85.832 85,832 85.832 85,832 85,832 85,832 85,832 85,832 85.832 85,832 82725 82725 2011.823UNTFOPER.EXPENSE (IS JTai) 262 264 265 212 202 202 202 202 202 202 200 200 200 200 200 200 200 200 200 200 200 193 193 4,802
INIERISTON LONGTERM 1 0 0 0 2847 2563 2278 1.993 1,708 1.424 1,139 854 569 285 0 0 -0 0 0 •0 0 0 -0 -0 15,661INIERGST ON LONG 1ERM 2 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0INIUREST ON LONG 1ERM 3 1302 801 402 T> 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 2.508
INIEREaTON LONG TERM 4 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0INTEREST ON LONG TERM DEBT 1302 801 402 2848 2563 2278 1,993 1,708 1,424 1,139 854 569 285 -0 0 0 -0 0 0 0 0 0 0 18170
[NIERESTONSIIORTTEKM DEBT 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
TOTAL PRODUCTION COST 113357 114,059 114,157 75,440 89,421 89.136 88851 88566 87,891 87,606 86686 86402 86117 85,832 85,832 85,832 85,832 85.832 85,832 85,832 85,832 82725 82725 2059.992UNrrpROD.cosT(Xs$zrni) 265 266 266 220 208 208 207 206 205 204 202 201 201 200 200 200 200 200 200 200 200 193 193
(e) Debts of Existing Plants and Repayments
The existing plants has the following long term loan at the start of the project. Their
loan amount and repqyment schedule are summarized below,
Unit: 1,000 DMR
Loan Amount 50,000 250,000 135,000
Repayment Period 3 years 3 years 3 years
Annual Interest Rate 17.5% 14.5% 12.0%
Repayment Schedule
-3rd Year 16,667 83,333 70,000
-2nd Year 16,667 83,333 32,500
—U Year 16,667 83,333 32,500
Unit:: 1,000 US$
Loan Amount 1,064 5,319 2,872
Repayment Period 3 years 3 years 3 years
Annual Interest Rate 17.5% 14.5% 12.0%
Repayment Schedule
—3rd Year 355 1,773 1,489
-2nd Year 355 1,773 691
—la Year 355 1,773 691
The above amount are taken into account for both Without and With Cases.
(f) Amount with Interest
Repayment
1st Repayment
Grace Period
Interest
Limit
on Foreign Long Term Loan
: 10 annual equal installments
: after the commercial operation start
: 0 year
: 7.0 % per year (Export Credit of JBIC is assumed for the
evaluation of profitability)
: US$40,678,000
Assumed all foreign currency of proejct cost, which is
66.9 % of total invenstment cost
-4-15-
(g) Amount with Interest on Local Long Tarm Loan
Repayment 5 annual equal installments
1st Repayment
Grace Period
after the commercial operation start
0 year
Interest 13.75 % per year
Limit Not required because all local currency portion is assumed
to be covered by equity.
-4-16-
4.1.4 F inancial Evaluation
(1) Conditions of Financial Evaluation
Conditions of financial evaluation of this project are as follows.
1) Construction Schedule
Construction Period 31 months after contract effective
Commissioning Period 2 months after mechanical completion
2) Operation Schedule
Commercial Operation Start Octorber, 2004
Operation Load:
Year Period Without With
- -3rd to -1* (Octorber 2001 to September 2004) 100% 100%
- 1st (Octorber 2004 to September 2005) 100% 80%
- 2nd to 20th (Octorber 2005 to September 2024) 100% 100%
3) Project Life
Project life for financial evaluation is counted for 20 years after revamping project,
that is, from the beginning of commercial operation Octorber 2004 to September
2024.
4) Currency Rate & Escalation Rate
Please refer to Section 4.1.1 (1) 1) & 2).
1.00 US$ = 105.00 JPY = 47.0 INR
(2) Financial Statements
(a) Production Cost Statement
Reference is made to Table 4.1-4 (1) & (2).
-4-17-
(b) Profit and Loss Statements
Reference is made to Table 4.1-5 (1) & (2).
(c) Cash Flow Statement
Reference is made to Table 4.1-6 (1) & (2).
(d) Project Balance Sheet
Reference is made to Table 4.1-7 (1) & (2).
(e) Financial Rate of Return
Reference is made to Table 4.1-8.
(3) Financial Internal Rate of Return (F1RR)
Since the project is revamping project, the financial internal rate of return is calculated as
below.
- Investment Cost: Proejct cost for revamping
- Profit from the Project: Increment of cashflow between Without Case and With
Case
(a) FIRR on Investment (ROI)
- Before Tax 35.21 %
- After Tax 28.19 %
(b) FIRR on Equity (ROE)
- Before Tax 63.68 %
- After Tax 49.78 %
-4-18-
MUS$Table 4.1-5(1) INCOME STATEMENTS (Profit and Loss Statements) FOR WITHOUT CASE
YEAR 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 TOTAL
OPERATING INCOME 107,250 107,250 107,250 107,250 107.250 107,250 107,250 107,250 107,250 107,250 107,250 107,250 107,250 107,250 107,250 107,250 107,250 107,250 107,250 107,250 107,250 107,250 107,250 2,466,750
TOTAL SALES REVENUE 107,250 107,250 107,250 107,250 107,250 107,250 107,250 107,250 107,250 107,250 107,250 107,250 107,250 107,250 107,250 107,250 107,250 107.250 107,250 107,250 107,250 107,250 107,250 2466750
COSTOFSALES 110,957 111,957 112,457 110957 110957 110957 110957 110957 110957 110957 110322 110,322 110,322 110322 110322 110,322 110322 110322 110,322 110,322 110,322 110322 110322 2546247
VAIJABI £ COST 101,612 101,612 101,612 101,612 101,612 101,612 101,612 101,612 101,612 101,612 101,612 101,612 101,612 101,612 101,612 101,612 101,612 101,612 101,612 101,612 101,612 101.612 101,612 2337,083DIRECT FIXED COST 8,709 9,709 10209 8,709 8,709 8,709 8.709 8,709 8,709 8.709 8,709 8,709 8,709 8,709 8,709 8,709 8,709 8,709 8.709 8,709 8,709 8,709 8,709 202814DEPRECIAHON AND AMORTIZATION 635 635 635 635 635 635 635 635 635 635 0 0 0 0 0 0 0 0 0 0 0 0 0 6350INCREASEPROD INVENTORY(M INLB) 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
GROSS PROFTTONSALES -3,707 -4,707 5.207 -3,707 -3,707 -3,707 -3,707 -3,707 -3,707 -3,707 -3,072 -3,072 -3,072 -3,072 -3,072 -3,072 -3,072 -3,072 -3.072 -3,072 3,072 -3,072 -3,072 -79,497
SALES EXPENSES (PRODUCT) 1,190 1,190 1,190 1,190 1,190 1,190 1,190 1,190 1,190 1,190 1,190 1,190 1,190 1,190 1,190 1,190 1,190 1,190 1,190 1,190 1,190 1,190 1,190 27,370GENERA],AND ADMIN. EXPENSES 108 108 108 108 108 108 108 108 108 108 108 108 108 108 108 108 108 108 108 108 108 108 108 2480SALES (VALUABLE ADDED) TAX 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
OPERATING PROFIT -5,004 6004 6504 -5,004 -5,004 5.004 5,004 -5,004 5.004 -5,004 4,369 -4,369 -4,369 -4,369 -4,369 4369 4369 -4,369 4.369 -4,369 4369 -4,369 4,369 -109,347
NON OPERATING EXPENSES 1,302 804 402 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 2508
INTEREST ON LONG TERM DEBT 1,302 804 402 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 2508INIEREST ON SHORTTERM DEBT 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
NET PROFIT OR (LOSS) BEFORE TAX 6.307 6809 -6907 -5,004 -5,004 -5,004 -5,004 -5.004 -5,004 -5,004 -4,369 -4,369 4369 4.369 4,369 -4,369 4,369 -4,369 4,369 4,369 -4,369 4369 4,369 -111,855
INCOMETAX 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
NET PROFIT OR (LOSS) AFTER TAX -6,307 -6809 -6907 -5,004 5,004 5,004 -5,004 -5,004 -5,004 -5,004 -4,369 -4,369 4,369 4.369 4,369 4369 4,369 -4,369 -4,369 -4,369 -4,369 -4,369 -4.369 -111,855
DIVIDENDS 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
RETAINED EARNINGS 6,307 6809 -6907 5,004 -5,004 -5,004 5,004 -5,004 -5,004 -5,004 4,369 4,369 -4,369 -4,369 -4,369 -4,369 4369 -4,369 -4,369 4,369 -4.369 -4,369 -4,369 -111,855
Table 4.1-5(2) INCOME STATEMENTS (Profit and Loss Statements) FOR WITH CASE M US$
YEAR 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 TOTAL
OPERATING INCOME 107,250 107,250 107,250 85,800 107,250 107,250 107,250 107,250 107,250 107,250 107,250 107,250 107,250 107,250 107,250 107,250 107,250 107,250 107,250 107,250 107,250 107,250 107,250 2,445,300
TOTAL SALES REVENUE 107,250 107,250 107.250 85,800 107,250 107,250 107.250 107,250 107,250 107,250 107,250 107,250 107,250 107,250 107,250 107,250 107,250 107,250 107,250 107,250 107,250 107,250 107,250 2,445,300
C06TOFSALES 110,957 111,957 112,457 71,294 85,560 85,560 85,560 85,560 85,169 85,169 84,534 84,534 84,534 84,534 84,534 84,534 84,534 84,534 84,534 84,534 84,534 81,427 81,427 2,011,973
VAITABLE COST 101,612 101,612 101,612 57,063 71,329 71,329 71,329 71,329 71,329 71,329 71,329 71,329 71,329 71,329 71,329 71,329 71,329 71,329 71,329 71,329 71,329 71,329 71,329 1,717,149DIRECT FIXED COST 8,709 9,709 10,209 10,098 10098 10098 10098 10,098 10,098 10098 10098 10,098 10,098 10098 10098 10098 10,098 10098 10098 10098 10,098 10,098 10098 230,587DEPRECIATION AND AMORTIZATION 635 635 635 4,133 4,133 4,133 4,133 4,133 3,742 3,742 3,107 3,107 3,107 3,107 3,107 3,107 3,107 3,107 3,107 3,107 3,107 0 0 64,237INCREASE PROD INVENTORY(MINIS) 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
GROSS PROMT ON SALTS 3,707 -4,707 -5,207 14,506 21,690 21,690 21,690 21,690 22,081 22,081 22,716 22,716 22,716 22,716 22,716 22,716 22,716 22,716 22,716 22,716 22,716 25,823 25,823 433,327
SALES EXPENSES (PRODUCT) 1,190 1,190 1,190 1,190 1,190 1,190 1.190 1.190 1,190 1,190 1,190 1,190 1,190 1,190 1,190 1,190 1,190 1,190 1,190 1,190 1,190 1,190 1,190 27,370GENERAL AND ADMIN. EXPENSES 108 108 108 108 108 108 108 108 108 108 108 108 108 108 108 108 108 108 108 108 108 108 108 2.480SALES (VALUABLE ADDED) TAX 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
OPERATING PROFIT -5,004 -6,004 -6,504 13,208 20392 20,392 20392 20392 20783 20783 21,418 21,418 21,418 21,418 21,418 21,418 21,418 21,418 21,418 21,418 21,418 24,525 24,525 403,477
NONOPERATING EXPENSES 1,302 804 402 2,848 2563 2,278 1,993 1,708 1,424 1,139 854 569 285 0 0 -0 -0 0 0 -0 -0 -0 0 18,170
INIERESTON LONG PERM DEBT 1,302 804 402 2,848 2,563 2,278 1,993 1,708 1,424 1,139 854 569 285 0 0 -0 -0 -0 0 0 0 -0 0 18,170INTEREST ON SHORT TERM DEBT 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
NETPROFTPOR (LOSS) BEHDRETAX -6,307 -6,809 -6,907 10,360 17,829 18,114 18,399 18,684 19,359 19,644 20564 20848 21,133 21,418 21,418 21,418 21,418 21,418 21.418 21.418 21,418 24525 24,525 385.308
INCOMETAX 0 0 0 4,025 6,927 7,037 7,148 7,259 7,521 7,632 7,989 8,100 8,210 8,321 8,321 8,321 8,321 8,321 8,321 8.321 8,321 9,528 9528 157,470
NEP PROFIT OR (LOSS) AFTER TAX 6,307 6,809 6,907 6(335 10,903 11,077 11,251 11,425 11,838 12,012 12,575 12,749 12,923 13,097 13,097 13,097 13,097 13,097 13,097 13.097 13,097 14,997 14,997 227,837
DIVIDENDS 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
RETAINED EARNINGS -6,307 -6,809 -6,907 6,335 10,903 11,077 11,251 11,425 11,838 12,012 12,575 . 12,749 12,923 13,097 13,097 13,097 13,097 13,097 13,097 13,097 13,097 14,997 14,997 227,837
Table 4.1-6(1) CASHFLOW STATEMENT (FUNDS FLOW STATEMENT) FOR WITHOUT CASE M US$
YEAR 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 TOTAL
SOURCEOFFUNDS -4.369 5,369 -5,869 -4,369 -4,369 4,369 -4,369 4,369 -4,369 -4,369 -4,369 -4,369 -4,369 -4,369 -4,369 4369 4,369 -4.369 -4,369 -4,369 -4,369 4369 4,369 102997
CASH GENERATED FROM OPERATION -4,369 -5,369 -5,869 -4,369 -4,369 -4,369 -4,369 4,369 -4,369 -4,369 -4,369 -4,369 -4,369 -4.369 -4,369 -4,369 -4,369 -4,369 4,369 4,369 4,369 -4,369 -4,369 -102997
PROETT AFT. TAX BER. INT. 5,004 ■6,004 6504 -5,004 5.004 -5,004 -5,004 -5.004 -5,004 -5.004 -4,369 -4,369 4,369 -4,369 4,369 4,369 -4,369 -4.369 -4,369 4,369 -4,369 4,369 -4,369 109,347DEPRECIATION AND AMORTIZAT. 635 635 635 635 635 635 635 635 635 635 0 0 0 0 0 0 0 0 0 0 0 0 0 6,350
FINANCIAL RESOURCES 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
SHARE CAPITAL 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0LONG TERM DEBT 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0SHORTTERM DEBT 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
USES OF FUNDS 4,919 3,623 3,221 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 11,763
FIXED CAPH'AL EXPENDHURE 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
NON DEPRECIABLE ASSETS 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0DEPRECIABLE FIXED ASSETS 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0DEFERED ASS ETS(INCLUDE IDC) 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
CHANGE IN WORKING CAP H AL 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
DEBTSERVKE 4,919 3,623 3,221 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 11,763
REPAY. OF LONG TERM DEBT 3,617 2.819 2,819 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 9,255REPAY. OFSHORTTERM DEBT 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0INTEREST OF LONG TERM DEBT 1,302 804 402 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 2508INTERESTOFSHORTTERM DEBT 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
DIVIDENDS 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
CASH INCREASE OR (DECREASE) -9,288 -8,993 9,091 4,369 -4,369 -4,369 4,369 4.369 -4,369 -4,369 -4,369 4,369 -4,369 -4.369 -4.369 -4,369 -4,369 -4,369 -4,369 -4,369 -4,369 4,369 -4.369 -114,760
BEGINNING CASH BALANCE 0 -9,288 -18,281 -27,372 -31,741 -36,111 40.480 44.849 49,219 -53,588 -57,958 -62,327 -66,696 -71,066 -75,435 -79.805 84,174 88,544 -92,913 -97.282 -101,652 -106,021 -110,391 -2667.553ENDING CASH BALANCE -9,288 -18,281 -27,372 -31,741 -36,111 -40,480 44,849 49,219 53,588 -57,958 -62,327 66,696 -71,066 -75,435 -79,805 -84,174 88,544 92,913 -97,282 101,652 -106,021 -110,391 -114,760 -2782313
Table 4.1-6(2) CASHFLOW STATEMENT (FUNDS FLOW STATEMENT) FOR WITH CASE MUSS
YEAR 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 TOTAL
SOURCEOFFUNDS 7,175 17,999 20,049 13,316 17,599 17,488 17.377 17,267 17,004 16894 16536 16426 16315 16204 16204 16204 16204 16204 16204 16204 16204 14,997 14,997 371,076
CASHGENERATED FROM OPERATION 4,369 -5,369 5^69 13,316 17,599 17,488 17.377 17.267 17,004 16894 16536 16426 16315 16204 16204 16204 16204 16204 16204 16204 16204 14,997 14,997 310244
PROITT AFT. TAX. BER. INI'. -5,004 -6,004 6,504 9,183 13,465 13,355 13,244 13,134 13,262 13,151 13,429 13.318 13,208 13,097 13,097 13,097 13,097 13,097 13,097 13,097 13,097 14,997 14,997 246007DEPRECIATION AND AMORTIZAT. 635 635 635 4,133 4,133 4,133 4,133 4,133 3.742 3,742 3,107 3,107 3,107 3,107 3,107 3,107 3,107 3,107 3,107 3,107 3,107 0 0 64,237
FINANCIAL RESOURCES 11,545 23,368 25,919 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 60832
S HARE CAPITAL 3.568 7,416 9,169 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 20,153LONGTERM DEBT 7,976 15,952 16,750 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 40,678SHORTTERM DEBP 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
LEES OF FUNDS 16,463 26,992 29,140 5,426 6.631 6346 6,061 5,776 5,491 5,207 4,922 4,637 4,353 -0 -0 -0 -0 0 -0 0 -0 0 0 127,445
FIXED CAPITAL EXPENDITURE 11,545 23,368 25,919 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 60832
NON DEPRECIABLE ASSETS 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0DEPRECIABLE FIXED ASSEIS 11,545 23,089 24,244 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 58877DEFERED ASSEIS(INCLUDE IDC) 0 279 1,675 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 1,954
CHANGE IN WORKING CAPITAL 0 0 0 -1,490 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 -1,490
DEBPSEKVICE 4,919 3,623 3,221 6.915 6.631 6,346 6061 5,776 5,491 5,207 4,922 4,637 4,353 -0 -0 0 0 0 -0 -0 -0 -0 -0 68103
REPAY. OF LONG TERM DEBT 3,617 2,819 2,819 4,068 4,068 4,068 4,068 4,068 4,068 4,068 4.068 4,068 4,068 0 0 0 0 0 0 0 0 0 0 49,933REPAY. OFSHORTTERM DEBT 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0IN1ERESTOFLONGTERM DEBT 1,302 804 402 2,848 2.563 2,278 1.993 1,708 1,424 1.139 854 569 285 0 0 0 -0 -0 -0 -0 0 0 0 18170DMIERESTOFSHORTTERM DEBT 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
DIVIDENDS 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
CASH INCREASEOR (DECREASE) -9,288 -8,993 -9,091 7.890 10968 11,142 11,316 11,490 11,513 11,687 11,614 11,788 11,963 16204 16204 16204 16204 16204 16204 16204 16204 14,997 14,997 243,631
BEGINNING CASH BALANCE 0 -9,288 -18,281 -27.372 -19,481 -8,514 2,629 13,945 25,435 36948 48.635 60,249 72,038 84,000 100,205 116409 132,614 148.818 165,023 181,227 197,432 213,636 228.633 4,424,878ENDING CASH BALANCE -9,288 -18,281 -27,372 -19,481 -8,514 2,629 13,945 25,435 36948 48,635 66249 72,038 84,000 10Q.205 116409 132,614 148,818 165,023 181,227 197,432 213,636 226633 243.631 4,668509
Table 4.1-7(1) PROJECT BALANCE SHEET FOR WITHOUT CASE MUSS
YEAR 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024
ASSETS -3,574 -13,201 -22,927 27.932 -32936 -37,940 -42945 -47.949 -52954 -57.958 62327 66697 -71,066 -75,436 -79,805 -84,175 -88,544 92913 97.283 -101,652 -106022 -110391 -114,760
CURRENT ASSETS 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
OPERATING CASH 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0ACCOUNT RECEIVABLE 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0INVENTORIES 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
ACCOUNT EXCESS CASH -9,288 18,281 -27,372 -31,741 -36111 -46480 -44,849 -49,219 -53,588 -57.958 62327 66696 -71,066 -75,435 -79,805 -84.174 -88,544 92913 -97,282 -101,652 -106021 -110391 -114,760
NET FIXED ASSETS 5,715 5,080 4,445 3,810 3,175 2540 1.905 1,270 635 0 -0 -0 0 0 0 0 0 0 0 0 -0 -0 -0
INVESTMENT 6,350 6350 6350 6350 6350 6350 6350 6350 6350 6350 6350 6350 6350 6350 6350 6350 6350 6350 6350 6350 6350 6350 6350
NON DEPRECIABLE ASSETS 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0DEPRECIABLE ASSETS 6,350 6350 6350 6350 6350 6350 6350 6350 6350 6350 6350 6350 6350 6350 6350 6350 6350 6350 6350 6350 6350 6350 6350DEFERRED ASSETS(INC.IDC) 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
LESS: ACCOUNT DEPRECIATION 635 1,270 1,905 2540 3,175 3,810 4,445 5,080 5,715 6350 6350 6350 6350 6350 6350 6350 6350 6350 6350 6350 6350 6350 6350
IJABILmES 5,638 2,819 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
CURRENT IJABOJITES 2,819 2,819 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
ACCOUNT PAYABLE 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0CURRENT PORTION OF L/T DEBT 2,819 2,819 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
SHORTTERM DEBT 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
FIXED IJABILmES 2,819 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
LONG TERM DEBT BALANCE 2,819 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0OTHER FIXED IJABILmES 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
STOCK HOLDERS EQUITY 6307 13,115 -20,022 -25,026 30,031 -35,035 -40,039 -45,044 -56048 -55,053 -59.422 63,791 68.161 72530 -76900 -81,269 -85,639 90008 -94,377 98,747 -103,116 -107.486 111,855
SHARE CAPITAL 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0ACCOUNT RETAINED EARNINGS -6,307 13.115 -26022 25,026 30,031 -35,035 46039 -45,044 -56048 -55,053 -59,422 63.791 68,161 -72530 -76900 -81,269 85.639 -90,008 -94,377 -98,747 -103,116 -107,486 111.855
UABiums &S/H EQUTIY -668 -10,296 20,022 -25,026 30,031 -35,035 -46039 -45,044 -50.048 -55,053 -59,422 63.791 68,161 -72530 -76900 -81,269 -85.639 -90,008 -94,377 -98,747 -103,116 -107,486 111,855
-24-
Table 4.1-7(2) PROJECT BALANCE SHEET FOR WITH CASE M us$
YEAR 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024
ASSETS 7,971 21,712 37.904 40172 48,496 55,505 62,688 70045 77,816 85,760 94,267 102,948 111,803 124,900 137,998 151,095 164,192 177,289 190,386 203,483 216580 231,577 246574
CURRENT ASSETS 0 0 0 -1,490 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
OPERATING CASH 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0ACCOUNT RECEIVABLE 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0INVENTORIES 0 0 0 -1,490 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
ACCOUNT EXCESS CASII -9,288 -18,281 -27,372 -19,481 8,514 2,629 13,945 25,435 36,948 48,635 60,249 72,038 84,000 100205 116409 132,614 148,818 165.023 181,227 197,432 213,636 228,633 243,631
NET FIXED ASSETS 17.259 39.993 65,276 61,143 57,010 52,877 48,743 44,610 40868 37,125 34,018 30,911 27.803 24,696 21,588 18,481 15,373 12,266 9,159 6051 2,944 2,944 2944
INVESTMENT 17,894 41,263 67,181 67,181 67,181 67,181 67,181 67,181 67,181 67,181 67,181 67.181 67,181 67,181 67,181 67,181 67,181 67,181 67,181 67,181 67,181 67,181 67,181
NON DEPRECIABIJS ASSEIS 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0DEPRECIABLE ASSETS 17,894 41X983 65,227 65,227 65,227 65,227 65,227 65,227 65.227 65,227 65,227 65.227 65,227 65.227 65.227 65.227 65,227 65,227 65,227 65,227 65,227 65,227 65,227DEFERRED ASS EISflNC.IDC) 0 279 1.954 1,954 1,954 1.954 1,954 1,954 1,954 1,954 1,954 1,954 1,954 1,954 1,954 1,954 1,954 1,954 1.954 1,954 1,954 1,954 1,954
LESS: ACCOUNT DEPRECIATION 635 1,270 1,905 6,038 10171 14,305 18,438 22,571 26,313 30056 33,163 36,271 39,378 42,486 45,593 48,700 51,808 54,915 58,023 61,130 61,237 61,237 61,237
UABILTTTFS 13,614 26,748 40,678 36,611 32,543 28,475 24,407 20339 16,271 12,203 8,136 4,068 -0 0 -0 0 -0 -0 -0 -0 -0 0 0
CURRENT IJABOTITES 2,819 1819 4,068 4,068 4.068 4,068 4,068 4,068 4,068 4,068 4,068 4,068 0 0 0 0 0 0 0 0 0 0 0
ACCOUNT PAYABLE 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0CURRENT PORTION OF I/T DEBT 2,819 1819 4,068 4,068 4,068 4,068 4,068 4,068 4,068 4.068 4,068 4,068 0 0 0 0 0 0 0 0 0 0 0SHORTTERM DEBT 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
FIXED I1ABIITTIES 10,795 23508 36,611 32,543 28,475 24,407 20,339 16,271 12,203 8,136 4,068 0 -0 -0 -0 -0 -0 -0 -0 -0 -0 -0 0
LONG TERM DEBT BALANCE 10,795 23,928 34611 32,543 28,475 24,407 20339 16,271 12,203 8136 4,068 0 -0 0 -0 0 -0 -0 -0 0 -0 0 0OTHER FIXED LIABILITIES 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
STOCK HOLDERS EQUITY 2.738 -1131 131 6,467 17,370 28.446 39,697 51,122 62.960 74.973 87,547 100296 113,219 126316 139,413 152.510 165,608 178,705 191,802 204,899 217,996 232993 247,990
SHARE CAPITAL 3,568 10,984 21X153 20,153 20153 20153 20,153 20,153 20153 20153 20,153 20,153 20153 20153 20153 20,153 20,153 20153 20,153 20,153 20153 20,153 20.153ACCOUNT RETAINED EARNINGS 6,307 -13,115 -20022 -13,686 -2,784 8,293 19,544 30969 42,807 54,820 67,394 80,143 93.066 106163 119,260 132,357 145,454 158,551 171,618 184,746 197,843 212840 227,837
IJABILTITFS & S/H EQUITY 10L876 24.617 40810 43,077 49,912 56,921 64,104 71,461 79,232 87,176 95,683 104.364 113,219 126316 139,413 152,510 165,608 178,705 191,802 204.899 217,996 232993 247,990
Table 4.1-8 INTERNAL RATE OF RETURN MUSS
YEAR FIXED CHANGE IN (l)GROSS OPERATING DEPRECIATN (2)GR06S (3)lNCOME (4)BFR-TAX (5)AFT-TAX (6)LONG TERM (7)DEBT (8)BFRTAX (9)AFT-TAX P.CKCAPITAL WORKING CAPITAL PROFIT CASH TAX NET IN FLOW NET IN FIOW DEBT SERVICE NET IN FLOW NETIN FIjOW
EXPENDITURE CAPITAL EXPENDITURE IN FLOW ONROI ONROI ON ROE ON ROE(w/oIDC) PHI) (<H3) (4M6)OR(7) (5)+<6>OR(7)
3 2002 11,545 0 11,545 0 0 0 0 11.545 11.545 7,976 0 -3,568 3.568 0.00-2 2003 23,089 0 23,089 0 0 0 0 -23.089 -23,089 15,952 0 -7,416 -7,416 0.00-1 2004 24,244 0 24,244 0 0 0 0 -24,244 24.244 16,750 0 9,169 -9,169 0.00
1 2005 0 0 0 18,212 3,498 21,711 4,025 21,711 17,686 0 6,915 14,795 10,770 4.762 2006 0 0 0 25,397 3,498 28895 8927 28895 21,968 0 6,631 22,264 15,3.37 5.323 2007 0 0 0 25,397 3,498 28895 7,037 28895 21,857 0 6,346 22,549 15,511 5.894 2008 0 0 0 25,397 3,498 28895 7,148 28895 21,747 0 6.061 22.834 15,686 6.645 2009 0 0 0 25,397 3,498 28895 7,259 28895 21,636 0 5,776 23,118 15,860 7.676 2010 0 0 0 25,787 3,107 28895 7,521 28895 21,374 0 5,491 23,403 15,882 9.207 2011 0 0 0 25,787 3,107 28895 7,632 28895 21,263 0 5,207 23,688 16,056 11.738 2012 0 0 0 25,787 3,107 28895 7,989 28895 20906 0 4,922 23,973 15,984 16.749 2013 0 0 0 25.787 3,107 28895 8100 28895 20795 0 4,637 24,258 16,158 31.76
10 2014 0 0 0 25,787 3,107 28895 8210 28895 20685 0 4,353 24,542 16,332 0.0011 2015 0 0 0 25,787 3,107 28895 8321 28895 20574 0 •0 28895 20574 0.0012 2016 0 0 0 25,787 3,107 28895 8321 28895 20574 0 0 28895 20574 0.0013 2017 0 0 0 25.787 3,107 28895 8321 28895 20574 0 0 28895 20574 0.0014 2018 0 0 0 25,787 3,107 28895 8321 28895 20574 0 0 28895 20574 0.0015 2019 0 0 0 25,787 3,107 28895 8321 28895 20574 0 0 28895 20,574 0.0016 2020 0 0 0 25,787 3,107 28895 8321 28895 20574 0 -0 28895 20574 0.0017 2021 0 0 0 25,787 3,107 28895 8321 28895 20574 0 -0 28895 20,574 0.0018 2022 0 0 0 25,787 3,107 28895 8321 28895 20574 0 0 28895 20,574 0.0019 2023 0 0 0 28,895 0 28895 9,528 28895 19,367 0 0 28895 19,367 0.0020 2024 2,944 0 -2.944 28,895 0 28895 9,528 31.839 22,311 0 0 31,839 22,311 0.00
0 0 0 0 0 0 0 0 0 0 0 0 0 0.00
INTERNAL RATE OF RETURN PAYBACK PERIOD
BFRTAX AETTAX BFRTAX AETTAX SENSITIVITY ANALYSISIRR on INVEST 3521 28.19 % SIMPLE (No Dismount) 3 3 Years
IRR on EQUITY 63.68 49.78 % DCFRATE 10.00% 4 5 Years Factor Orignal FactoredERECTION COST 1.00 0 0 MUSSUREA 1.00 250 250 USS/TonNaphtha l.O) 333 333 LSS/MT
(4) Sensitivity Analysis on ROI before Tax
In order to discuss the project profitability, the sensitivity analysis for ROI before Tax is
conducted against the Natural Gas of raw material price between US$ 4.0 to 6.0 per
MMBtu. For Urea product cost the same sensitivity analysis is conducted between 60 to
120 %. For Erection cost the same sensitivity analysis is conducted between 80 to 120 %.
Since the ROI before Tax has no effect on the payment of its loan interest and income tax,
the ROI before Tax is widely used for the profitability evaluation.
The calculated results are shown below and shown in Figure 4.1-1 through 4.1-3 for
Natural Gas price, Urea price and Erection cost respectively.
Sensitivity Analysis of ROI
Product Name Unit Price ROI before Tax, %
Natural Gas 4.00 US$/MMBtu 49.76
6.00 US$/MMBtu 3521
8.00 USS/MMBtu 16.50
Product Urea 150.0 US$/Ton 37.55
250.0 US$/Ton 3521
300.0 US$/Ton 34.09
Erection Cost 47,102,000 US$ 41.93
58,877,000 US$ 3521
70,652,000 US$ 30.33
No conversion of raw material 14.77
from Naphtha to Natural gas
Notes: Bold figures are the base figures of this feasibility study.
The raw material natural gas shares more than 50 % of production cost and it is very
sensitive on project profitability. But product urea price does not affect project profitability,
because production amount is not changed by the project. Product urea is important for
Z3L financial soundness.
If raw material of naphtha is not changed to natural gas, ROI before tax is calculated at
14.77 % and it is understood that conversion from naphtha to natural gas contributes very
much to proejct profitability improvement.
-4-26-
23456789Natural Gas price US$/MMBtu
Fig. 4.1-1 Natural Gas Price vs ROI
50se 40&
% 30
S 20
§ 10r\
: I-------------- --------------------------- --
: . !
: I: |
100 150 200 250 300 350Product Urea Sales Price US$/T
Fig. 4.1-2 Product Urea Sales price vs ROI
60% 70% 80% 90% 100% 110% 120% 130% 140%Total Investment Cost %
Fig. 4.1-3 Total Investment Cost vs ROI
-4-27-
(5) Evaluation
(a) Sales.Revenue
Total sales revenue for the whole project period comes from sales revenue only. The
annual sales revenue of Without Case is calculated to be 107,250 MUSS as shown is
Table 4.1-1 (1) for whole 23 years project life, which is composed 3 years
construction and 20 years operation periods.
The annual sales revenue of With Case is calculated to be 107,250 MUSS whole 3
years construction period because operation continues for the same period. But the
first year annual sales revenue is calculated at 85,800 MUSS, because plant shutdown
is expected due to tie-in work between new facilities and existing faclities and intial
trouble, which causes 80 % of operation load.
-4-28-
(b) Production Costs
The annual total production costs, consist of the factory cost and the operating
expenses for the whole project period is summarzed below,which detail is shown in
Table 4.1-4(1) and (2).
Without Case
MUSS
113,557 to 111,619
With Case
During construction period 113,557 to 114,157
la year of operatic 75,440
2nd year and onward operation period 89,421 to 82,725
Based on above, average production cost per urea ton are calculated below.
Without Case US$/Urea-Ton
261.4
With Case
During construction period 265.6
la year of operatic 219.8
2nd year and onward operation period 201.5
(c) Profit
The total operating profit for the whole project period is calculated below, which
detail are shown in Table 4.1-5 (1) & (2).
Without Case
MUSS
-6,307 to-4,369
With Case
During construction period - 6,307 to - 6,907
la year of operatic + 6,335
2nd year and onward operation period +10,903 to +14,997
-4-29-
(d) Evaluation
The project continues its negative profit without revamping project based on
estimated urea price of US$/Ton 250. The cashflow also continues its negative figure.
If urea price goes up by US$/Ton 11 or naphtha price comes down by US$/Ton 21
from base price of US$/Ton 333.43, cashflow turns to positive.naphtha price. When
project is implemented, natural gas price is lower than naphtha one and improvement
of profit is expected with positive cashflow.
The project profitability is very high because of raw material conversion and energy
consevation.
Current production cost is very high and is not competitive to international urea price
level. After proejct implementation, the same production cost goes down up to
US$/Ton 193 - 208, which is more than US$/Ton 50 cheaper than current one.
In project execution stage in India a foreign contractor usualy applies asuumed
income of the project to the authority of India and pays 48% of assumed income as
income tax. After the project completed the final income is applied and plus and
minus of income tax are adjusted accordingly.
However this year the authority of India announced the expansion of taxation to
foreign contractors in order to increase tax ammount. In a certain project tax issue was
raised and the payment from India was deducted 48 % from contract price.
Accordingly it was very difficult to execute the project
This tax issue is very critical for foreign contractors to execute projects in India and
would take time to be settled. Therefore the project execution in India might be
difficult for foreign contractors without the settlement.
-4-30-
4.2 Cost versus Effects
4.2.1 Cost versus Energy Saving Effect
As described in 3.1.3 of CHAPTER 3, the quantity of the energy saving over the project
life is calculated as 55,705 toe/y. Intial investment cost for the project is 60,832
MUS$ (6,387 million JPY). Thus, the cost versus energy saving of the project is 8.72
toe-y/million JPY.
(Eq.): (55,705 toe-y)/(6,387 million JPY) = 8.72 toe-y/million JPY
4.2.2 Cost versus Greenhouse Performance Gas Reduction
The reduced quantity of C02 gas as the greenhouse performance gas is estimated to be
245,139 t-COo/y as described in CHAPTER 3. Intial investment cost for the project is
60,832 MUS$ (6,387 million JPY). Thus, the cost versus greenhouse performance gas
reduction is 38.4 t-C02-y/million JPY.
(Eq.): (245,139 t-CQ2/y)/(6,387 million JPY) = 38.4 t-C02-y/million JPY
-4-31-
CHAPTER 5
SPREAD EFFECTS
Summary: Spread possibility of the applied technologies for the project in other area in India was examined. And further, quantitative evaluation and estimation on effects of energy saving and greenhouse performance gas reduction were made for the case after being spread.
CHAPTER 5 SPREAD EFFECTS
5.1 Spread Possibility of the Applied Technology in other area
Production capacity of ammonia plants using naphtha as feedstock and fuel is
approximately 36 % in India. Most of naphtha based ammonia plants consume much
energy like ZIL.
There are 11 ammonia plants as listed below, which were constructed in 1960s-1970s like
ZIL and are still operated Most of the plants were revamped for the purpose of capacity
increase, but the energy consumption are still very high compared with latest and modem
plants.
Owner Location Capacity (Ammonia/Urea)
1) Gujarat State Fertilizer Co., Ltd Vadodara I,II,II Total 1050/1120 t/d
2) Coromandel Fertilizers Ltd Vizag 357/400 t/d
3) Shriram Fertilizer & Chemicals Kota 560/1000 t/d
4) Duncans Industries Ltd Plant-1,11,111
Panki I,II,III Total 1240/2045 t/d
5) Mangalore Chemicals &Fertilizers Ltd
Mangalore 660/1030 t/d
6) Southern PetrochemicalIndustries Corp. Ltd
Tuticorin 1100/1600 t/d
7) Indian Farmers Fertilizer Cooperative Ltd
Phulpur 910/1500 t/d
8) The Fertilizers and Chemicals Travancore Ltd
Cochin 600/1000 Vd
9) Madras Fertilizers Ltd Chennai 1275/1475 t/d
These plants need revamp of energy saving and feedstock change like ZIL in accordance
with the guideline of fertilizer subsidy policy with 3 steps reducing amount of subsidy.
Therefore spread possibility of the applied technologies in other fertilizer plants is very
high.
-5-1-
5.2 Effects under Spread Consideration
5.2.1 Effects on Energy Saving
Effects of energy saving depend on the level of energy consumption. According to the
survey in India for this F/S there are 3 fertilizer plants (listed below) with similar level of
energy consumption as ZJL.
Owner Location Capacity(Ammonia/Urea) Sector
- Mangalore Chemicals &Fertilizers Ltd
Mangalore 660/1030 t/d private
- Southern Petrochemical Industries Corp. Ltd
Tuticorin 1100/1600 t/d private
- The Fertilizers and Chemicals Travancore Ltd
Cochin 600/1000 t/d public
Total 2360/3630 t/d
Assuming that above all fertilizer plants could save energy with applying energy saving
technologies and feedstock conversion like the project total effects of energy saving could
be estimated as 163,119 toe/y after calculated with capacity slide of ammonia and urea
plants.
ZIL Capacity Energy Saving as crude oil equivalent
Ammonia 750 t/d 36,383 toe/y
Urea 1,300 t/d 17,417 toe/y
Total 53,800 toe/y
3 plants total
Ammonia 2,360 t/d 114,485 toe/y
Urea 3,630 t/d 48,634 toe/y
Total 163,119 toe/y
-5-2
5.2.2 Effects on Greenhouse Performance Gas Reduction
In similar approach to the above, the yearly reduction of C02 gas emission is expected to
be approximately 727,232 t-COz/y, in case that the same technologies applied to this
project would be spread over other 3 fertilizer plants.
711. Capacity Reduction of C02 emission
Ammonia 750 t/d 183,289 t-COz/y
Urea 1300 t/d 53,892 t-COz/y
Total 237,181 t-COz/y
3 plants total
Ammonia 2,360 t/d 576,749 t-COz/y
Urea 3,630 t/d 150,483 t-COz/y
Total 727,232 t-COz/y
-5-3-
CHAPTER 6
EFFECTS to OTHERS
Summary: Evaluation was made on other effects such as environmental, economical and social effects due to implementation of the project than the effects on energy saving and greenhouse performance gas reduction
described in CHAPTER 3.
CHAPTER 6 EFFECTS to OTHERS
6.1 Environmental Effects
The plants revamped for the project fire fuel to supply energy required for production of
fertilizer. So huge amount of C02 and steam are released to the atmosphere together with
combustion heat as well as some NOx. The project can reduce fuel consumption by energy
saving, thus can reduce C02 and NOx.
Sulfur is contained in naphtha feedstock and fuel. Sulfur in feedstock naphtha will be
removed prior to feed to the process. The removed sulfur as gaseous phase is fired in a
furnace and vented to the atmosphere as sulfur oxide. Sulfur in fuel naphtha will be vented as
sulfur oxide after firing. Therefore the energy saving for the project can reduce emission of
sulfur oxides.
The project incorporating feedstock conversion from naphtha to natural gas can also reduce
emission of sulfur oxide, because sulfur in natural gas is smaller than naphtha.
Regarding effluent water as another environmental effects, ZJL has a policy of zero effluent
discharge and achieved it in 1989. The project is designed considering the same policy of
zero effluent discharge from the plants. Therefore no effects against environment is
achieved in the project.
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6.2 Economical Effects
As described before, this project was strongly requested by ZEL to survive in fertilizer
business against high feedstock price and reduction of fertilizer subsidy. ZIL needs
improvement of production cost in order to survive in fertilizer business against high
feedstock price and reduction of fertilizer subsidy.
The feedstock change and energy saving incorporated in the project is in accordance with the
guideline of fertilizer subsidy policy with 3 steps reducing amount of subsidy expected to
implemented by the government of India. After confirming economical feasibility and the
fertilizer policy of the government Z3L could have an intention to start the project. So the
project could contribute to the improvement of ZIL's finalcial performance after realization.
In addition spread possibility of the applied technologies in other fertilizer plants is very high.
The project could also contribute the improvement of agricultural and fertilizer industries.
ZEL was constructed as a first large factory in Goa. So the project could also contribute to
the local economy after realization.
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6.3 Social Effects
Following environmental and economical effects above, the social effects will be expected
after the project realization.
1) Security of Domestic Food Supply
Population of India almost reaches one billion and is estimated to become above China
in near future. Therefore food, fertilizer, energy, social overhead capital etc. should be
increased. Most of fertilizers necessary for agricultural product have been produced in
India to secure domestic supply of food. The government of India gives fertilizer
sector subsidy to retain retail price of fertilizer to secure domestic production.
Under the such subsidy policy old fertilizer plants with less efficiency are still operated
and drastic improvement has been suspended. Therefore production of fertilizer in
India became less competitive compared with international market. In order to improve
such situation old fertilizer plants with naphtha feedstock should be revamped to change
feedstock to natural gas and to reduce energy consumption, which are in compliance
with the guideline of long term policy on fertilizer sector expected to implement by the
government of India.
The spread possibility of the applied technologies in other fertilizer plants could be very
high. It is expected that the project could contribute the security of domestic food
supply.
2) Technology Transfer and Improvement
It is expected that the project related technologies such as plant design and engineering,
project development and management, plant construction and operation including
maintenance, etc will be transferred and improved in the regional area.
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CONCLUSION and RECOMMENDATION
CONCLUSION and RECOMMENDATION
Fertilizer production in old plants in India became less competitive compared with
international market under fertilizer subsidy policy by government of India. The F/S result
for without revamp case same as present condition shows minus cash flow through the total
project. The past minus cash flow has been compensated by subsidy from the government,
but the amount of subsidy was reduced from 2000 and the government decided to phase out
the urea subsidy by April 2006. Therefore old fertilizer plants with naphtha feedstock should
be revamped to change feedstock to natural gas and to reduce energy consumption for then-
survival.
The F/S result shows that the project including feedstock change and energy saving could
drastically reduce production cost compared with the without revamp case. The quantity of
C02 reduction including spread effect in India would be relatively large. Therefore it is
understood that urgent implementation of the project would be necessary.
However, it would take much time to disclose a detailed government policy, which is
under planning to proceed phasing out the existing subsidy and to complete decontrol of
urea by April 2006. The government recommends to change feedstock from naphtha to
natural gas in fertilizer plants. So there are many projects of LNG terminal and pipeline to
supply natural gas to fertilizer plants. But it would also take much time to materialize.
We, Toyo Engineering Corp. will watch and follow the government policy and investigate
projects of LNG terminal and pipeline as well as will support Zuari Industries Limited
(ZIL) as required in every phase of the above development and implementation of the
project.
Following actions are required for further development and implementation of the project:
Toyo to support ZIL to evaluate this project based on the government policy.
Toyo to investigate projects of LNG terminal and pipeline
Both Toyo and ZIL to enter into the preparation for Japanese fund
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ATTACHMENT
Reference List
1) Key Indicators, Statistics (1999-2000) of Finance Ministry, Government of India2) Sectoral Real Growth Rates in GDP, Statistics (1999-2000) of Finance Ministry,
Government of India3) Growth Rates of Core and Infrastructure Sectors, Statistics (1999-2000) of
Finance Ministry, Government of India4) C02 emissions, Statistics of Energy Information Administration (EIA)
Other References
- Background Paper on Long Term Policy on The Fertilizer Sector
- Annual Report 1999-2000
- Fertilizer Statistics 1998 - 99
- Fertilizer & Agriculture Statistics Northern Region
- Fertilizer & Agriculture Statistics Western Region
- Meeting India's Petroleum Requirements Demand Projections 2001-02 and 2006-07
- Zuari Industries Ltd. Annual Report 1998 - 1999
- Zuari Industries Ltd. Annual Report 1999 - 2000
- The Zuari-Chambal Group(Catalogue)
- 25 Years of Production at Fertilizer Division(Zuari Company History)- Statistical Hand Book of Goa 1998-99
- Official Telephone Directory (December 1999)
- Industrial Commercial & Foreign Trade Directory 1999
- Standards for Liquid Effluents, Gaseous Emissions, Automobile Exhaust, Noise and
Ambient Air Quality
- The Budget 2001-2002
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New Energy and Industrial Technology Development Organization (NEDO)
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