NFL Panipat PDD_ 25 Oct- 2011

7/29/2019 NFL Panipat PDD_ 25 Oct- 2011

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PROJECT DESIGN DOCUMENT FORM (CDM PDD) - Version 03

CDM Executive Board

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CLEAN DEVELOPMENT MECHANISM

PROJECT DESIGN DOCUMENT FORM (CDM-PDD)

Version 03 - in effect as of: 28 July 2006

CONTENTS

A. General description of project activity

B. Application of a baseline and monitoring methodology

C. Duration of the project activity / crediting period

D. Environmental impacts

E. Stakeholders comments

Annexes

Annex 1: Contact information on participants in the project activity

Annex 2: Information regarding public funding

Annex 3: Baseline information

Annex 4: Monitoring plan


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SECTION A. General description of project activity

A.1. Title of the project activity:

>> Feed Switch from FO/LSHS to Natural Gas for Ammonia & Urea Manufacture at Panipat 1

Version -1

Date: 1st

September 2011

A.2. Description of the project activity:

>> National Fertilizers Limited (NFL) is one of the leading producers of Nitrogenous Fertilizers in India.

NFL is presently operating a ammonia and urea plant at Panipat in India the feed stock / fuel used at the

plant is Heavy Fuel Oil/Low Sulphur Heavy Stock. Coal is used for captive power and steam generation.

The support / auxiliary fuel used in the coal fired boiler is the heavy oil.

The project activity involves switching of feed stock and support fuel from Heavy fuel oil to Natural Gas.Project activity will involve modifications/changes in ammonia reforming section and the associated

utilities. The objective of the project activity is to shift to the lesser carbon intensive feed stock and

support fuel for production of ammonia which leads to reduction in GHG emissions

Pre Project Scenario

In the pre project scenario, Heavy fuel oil is used as the feed stock and support fuel for production of

ammonia. Heavy oil is gasified with oxygen (produced separately in an air separation unit) and steam to

produce the gaseous streams consisting H2, CO2, CO, Ar and other inert gases. Heat contained in this hot

gas stream is recovered in the waste heat boiler. Subsequently CO2 is separated from the gaseous stream

and argon and other inert gases are removed from the stream. Nitrogen from the air separation unit is

added back to the gaseous stream to get the synthesis gas having hydrogen to nitrogen ratio of 1:3 (molar

ratio). The synthesis gas is then made to react in the ammonia reactor to produce ammonia. Heavy oil is

also used as a support fuel in the combined heat and power plant.

Post Project Scenario

After the implementation of project activity, Natural gas will be used as the feed stock and support fuel.

The technology for production of ammonia using natural gas as the feedstock is different from the

existing technology and this will require process changes in existing equipment as well as incorporation

of new processes like Methanation section, etc.

In the process of changeover from Heavy oil to Natural Gas, key physical changes which will be

incorporated in the ammonia plant for the implementation of project activity are as follows:

A new Desulphurizer section will be installed

A new primary reformer and secondary reformer will be installed A new S-300 convertor will be installed in the existing synthesis loop

A new CO2 removal/ recovery unit(MDEA wash) will be installed

A new Methanation section will be installed

A new Synthesis booster compressor will be installed

A new Medium pressure(40K) loop boiler in synthesis loop will be installed


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The technology for production of ammonia which will be used for project is the world class and will lead

to reduction in the consumption of hydrocarbons for the production of same volume of ammonia. Thus

the technology will also lead to the consequent reduction in the emissions of heavy metals, particulatesand other pollutants associated with the use of hydrocarbons.

A.3. Project participants:

>>

Name of Party involved (*)

((host) indicates a host party)

Private and/or public entity

(ies)

Project participants (*)

(as applicable)

Kindly indicate if the Party

involved wishes to be

considered as project

participant

(Yes/ No)

Government of India (host party) National Fertilizers Limited No

A.4. Technical description of the project activity:

A.4.1. Location of the project activity:

>> Panipat, India

A.4.1.1. Host Party(ies):

>> Government of India

A.4.1.2. Region/State/Province etc.:

>> State: Haryana

A.4.1.3. City/Town/Community etc.:

>> PanipatA.4.1.4. Details of physical location, including information allowing the unique

identification of this project activity (maximum one page):

>> The proposed CDM project activity is located in National Fertilizers Limited, District Panipat,Haryana State, India. The nearest airport is Indira Gandhi International airport New Delhi and nearest

railway station is Panipat railway station.

The location map is given below.


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Plant Address:

National Fertilizers Limited,

Gohana Road,

Panipat,

Haryana-132106.NFL Plant Geo - Coordinates: 2921'30"N 7657'40"E

A.4.2. Category(ies) of project activity:

>> The project activity switches high carbon intensive feed stock and support fuel to lower carbon

intensive feed stock and support fuel and hence reduces the GHG emissions to the atmosphere for the

same production of ammonia. According to the CDM modalities, the project activity falls under


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Approved Large scale methodology AM0050. The project activity corresponds to sectoral scope 5,

Chemical Industry of the UNFCCC sectoral scope list for project activities.

A.4.3. Technology to be employed by the project activity:

>> National Fertilizers Limited has hired M/sHalder Topse, who is the world renowned technology

provider in fertilizer plant and have provided technology to many of the fertilizer units in India and

abroad. National Fertilizer Limited has incorporated all necessary safety features which are required for

the safe operation of the plant.

The Purpose of Project activity is to adopt a cleaner and efficient technology and reduce the GHG

emissions by switching over of feed and support fuel from heavy oil to natural gas. The change over from

heavy oil to natural gas will reduce GHG emissions due to reduced generation of CO 2 in the reformer

section, boilers.

In the production process of ammonia using hydrocarbons as feed stock involves following sequential

steps:

Reforming of hydrocarbon with steam and oxygen / air followed by separation of carbon dioxide

and other impurities from the output gaseous stream of the reformer to produce synthesis gas.

Conversion of synthesis gas to Ammonia in a reactor

Separation of ammonia and recycling of the unreached synthesis gas back to the ammonia reactor

Apart from these main operations mentioned above the auxiliary operations in typical ammonia plant

may include the following:

Use of waste heat for generation of steam

Onsite generation of power and balance steam in combined heat and power plant leading to

emissions of GHG

Operation of boilers for generation of process steam leading to emissions of GHG

In the reforming section, hydrocarbon feed is reformed to make CO2, Hydrogen and Nitrogen. The CO2 is

then separated from the main gaseous stream in the CO2 recovery section. The gaseous stream also

contains some traces of CO, Argon and other inert gases and these traces are removed before production

of ammonia in the synthesis reactor.


In the scenario prior to the implementation of Project activity, Heavy oil is used as feedstock for the

reforming. The generation of ammonia using Heavy oil as feed involves following steps:

Gasification of heavy oil

CO Shift

CO2 recovery section Ammonia Synthesis

The process diagram shown below gives the details about the process equipment and various GHG

emissions sources in the existing practice of heavy oil as feed stock


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Emission - Utility

Emission - Grid

Combined

Heat and

Power(CH

P) Plant /

Process

Boilers /

Waste

HeatRecovery

Boilers

Fossil Fuel for Boilers

(coal)

Gasifier

Separation

of CO2

Ammonia Reactor

Urea Production

Supply Header / Hydrocarbon Storage Bunker

Heavy Fuel Oil

Emission

Feedstock

CO2 In Excess of

that used for

Urea

Production

Air

CO2

Power From / To Grid

Ammonia

Synthesis Gas

CO2

Emission - Heat

Auxiliary /

Support FuelFeed / Fuel

Urea

Hot Gas Stream

Waste

Heat

Recovery


CO2

The main GHG emission sources are emissions due to venting of Excess CO2 over and above used for

urea production , GHG emissions from the utilities like steam generators, GHG emissions due to import

of power from Grid.

A detailed residual life cycle assessment was carried out by National Fertilizers Limited and all the

existing units had adequate lifetime. The decision taken by NFL Panipat is based on the urge to adopt the

cleaner and efficient technology which will reduce consumption of hydrocarbons and hence the GHG

emissions for the same volume of production.


In the scenario after the implementation of Project activity, Natural Gas will be used as a source of feed

and support fuel for the production of ammonia. The generation of ammonia using Natural Gas as feed

involves following steps:

Feed gas compression, pre heating and desulphurization section

Primary and Secondary Reforming

Process air compression

CO Shift conversion

CO2 recovery section

Methanation section

Dryer and Purifier section

Ammonia Synthesis


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Loop purge ammonia recovery

Ammonia refrigeration

Process condensate stripper

The process diagram shown below gives details about the process equipment and various GHG emissions

sources after implementation of project activity with Natural Gas as feed stock and support fuel.

Emission - Utility

Emission - Grid

Combined

Heat and

Power(CH

P) Plant /

Process

Boilers /

Waste

Heat

Recovery

Boilers


(coal)

Gasifier

Separation

of CO2

Ammonia Reactor

Urea Production


Natural Gas

Emission

Feedstock

CO2 In Excess of

that used for

Urea

Production

Air

CO2


Ammonia

Synthesis Gas

CO2

Emission - Heat

Auxiliary /


Urea

Hot Gas Stream

Waste

Heat

Recovery


CO2

The main GHG emission sources at after the project activity remains the same however the emission

intensity reduces.

The project activity is being implemented in an existing ammonia production unit and involves

replacement of the existing front end section of ammonia plant with integration to existing back end

section of ammonia plant with a new S -300 convertor and MP boiler, keeping the existing off site and

utilities for production of ammonia.

List of new section that will be added for the implementation of CDM project activity are as follows:

Desulphurization section

Modification in the reformer section

CO2 removal/recovery unit (MDEA wash)

Methanation section

Synthesis gas booster compressor


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S-300 convertor

Medium Pressure loop boiler in synthesis loop

Ammonia recovery unit MP process condensate stripper

Natural gas pipeline network

The list of equipment that will become redundant/replaced after the implementation of project activity

are as follows:

Oxygen generation plant and its associated utilities

Front section of Ammonia plant

Rectisol unit of CO2 removal

Heavy oil storage section and piping network

In the absence of the project activity, NFL Panipat would have continued to use current practice of heavy

oil as feed stock and support fuel hence pre project scenario is also the baseline scenario.

Emission reduction due to the project activity would happen due to lower carbon intensity of Natural gas.

A.4.4. Estimated amount of emission reductions over the chosen crediting period:

>> The estimated amount of emission reduction due to the proposed project activity for the ten (10) years

under fixed crediting period option would be 4517960 tCO2e as per details on annual emission reductions

provided below:

Years Annual estimation of emission

reductions in tonnes of CO2 e

2012-13 451796

2013-14 451796

2014-15 451796

2015-16 451796

2016-17 451796

2017-18 451796

2018-19 451796

2019-20 451796

2020 -21 451796

2021-22 451796

Total estimated reductions

(tonnes of CO2e)

4517960

Total number of crediting years 10 years (Fixed)Annual average over the crediting

period of estimated reductions

(tonnes of CO2e)

451796


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A.4.5. Public funding of the project activity:

>> There is no public funding involved in the proposed CDM project activity.

SECTION B. Application of a baseline and monitoring methodology

B.1. Title and reference of the approved baseline and monitoring methodology applied to the

project activity:

>> The title of the baseline and monitoring methodology applicable to the proposed project activity is

Technology up-gradation and / or Fuel / Feed switch in integrated Ammonia manufacturing industry---

Version XX.

Reference: AM0050, Version XX, Sectoral Scope: 05.

It has been referred from the list of approved methodologies for CDM project activities in the UNFCCC

CDM website (http://cdm.unfccc.int/methodologies/PAmethodologies/approved.html).

AM0050 (Version XX) draws upon the following tools, which have been used in the PDD:

Combined tool to identify the baseline scenario and demonstrate additionality

Tool to calculate the emission factor for electricity system

B.2. Justification of the choice of the methodology and why it is applicable to the project

activity:

>> The proposed CDM project activity is a feed and a support fuel switch over from heavy oil to natural

gas and meets the applicability and non-applicability conditions of the chosen methodology (i.e. AM0050

VersionXX) as follows

Applicability Condition as per the approvedmethodology

Scenario in the Project activity

The project activity is carried out in an ammonia

plant, where, ammonia is sold as a merchant product

or converted to derivatives e.g., urea, ammonium

nitrate etc.

The project activity is carried out in an existing

ammonia plant hence this condition is applicable

to project activity

Ammonia manufacturing plants that are not

prevented by local regulations from using feedstock

and /or fuel other than natural gas

The project activity does not prevented by any

local regulation to switch to Natural gas and hence

this condition is applicable to project activity.

Project activities that do not result in the increase ofthe production capacity of ammonia plant. However,

the design capacity of ammonia plant may increase

marginally (say maximum up to 10 % of the design

capacity) and remain same throughout the crediting

period due to the need for line balancing. This is

required to be validated by the validating DOE by

In the Project scenario, name plate capacity of

ammonia plant will remain within the prescribedlimits as defined in the methodology hence this

condition is applicable.


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validating the design capacity of the ammonia reactor

before and after the project.

.

Natural gas is sufficiently available in the region or

country, e.g. future natural gas based capacity

additions, comparable in size to the project activity,

are not constrained by the use of natural gas in the

project activity1;

NFL has signed a long term MOU with Gas

Authority of India Limited(GAIL) for the reliable

and continuous supply of Natural Gas and hence

there will be ample gas available for the project

activity.

The ammonia manufacturing plant is an existing

plant with a historical operation of at least three years

prior to the implementation of the project activity;

NFL is operating this plant since 1974. The last

three year production details will be made

available to DOE during validation hence this


Although Project activities may result in changes in

the production process but there is no change in the

capacity and product mix to produce different

product types e.g., the proportion of a particular type

of product produced in the total product mix should

remain same before and after the implementation of

project activity.

The capacity for different product types and mix

before and after the implementation of project

activity remains same hence this condition is

applicable

Prior to the implementation of the project activity, nonatural gas has been used in the ammonia

manufacturing plant

No Natural Gas has been used prior to the start of

project activity hence this condition is applicable

In case of historic use of ammonia for the production

of urea, percentage of ammonia used for production

of urea historically should not decrease (except minor

variation of up to 5%)

The percentage of ammonia consumed for the

production of Urea will not decrease hence this


B.3. Description of the sources and gases included in the project boundary:

1In some situations, there could be price-inelastic supply constraints (e.g. limited resources without possibility of

expansion during the crediting period) that could mean that a project activity displaces natural gas that would

otherwise be used elsewhere in an economy, thus leading to possible leakage. Hence, it is important for the project

proponent to document that supply limitations will not result in significant leakage as indicated.


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>> According to the approved methodology AM0050 (Version xx, the spatial extent of the project

boundary includes the ammonia plant and power generation plant.

Emission - Utility

Emission - Grid

Combined

Heat and

Power(CH

P) Plant /Process

Boilers /

Waste

Heat

Recovery

Boilers


Gasifier / Reformer

Separation

of CO2

Ammonia Reactor

Ammonia Storage

/Derivative

Production


Hydrocarbon Feedstock /Fuel

Emission Feedstock

CO2 In Excess of

that used for

Derivatives

Air

CO2


Ammonia

Synthesis Gas

CO2

Emission - Heat

Auxiliary /


Ammonia /

Ammonia

Derivative

Hot Gas Stream

Waste

Heat

Recovery

Project Boundary

CO2

Source Gas Included? Justification / Explanation

Baseline

Processing

of feedstock

CO2 Yes Main emission source. CO2 is produced in the reforming

of the feed

CH4 No Negligible fugitive CH4 emissions may occur during the

processing of the feed. These emissions (if any) would be

essentially the same as in the project activity. Therefore,

they are excluded for simplification.

N2O No Not applicable.

Fuel used infurnaces

(thermal

energy)

CO2 Yes Depending upon the process technology used in the

baseline it may be a main emission source (flue gases) due

to the combustion of fossil fuel to provide thermal energy

for feed treatment (sulphur removal in hydrotreater andprimary desulphurization unit and the synthesis-gas

production).

CH4 No Excluded for simplification, this is conservative.

N2O No Excluded for simplification, this is conservative.


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Source Gas Included? Justification / Explanation

Fuel used inboilers

(Steam and /

or power

generation)

CO2 Yes Main emission source.

CH4 No These emissions are expected to be the same or higher as

compared to the project scenario. Excluded for

simplification and because this is conservative.

N2O No These emissions are expected to be the same or higher as



Grid

Electricity

requirement

CO2 Yes Main emission source

CH4 No These emissions are expected to be the same or higher as



N2O No These emissions are expected to be the same or higher as



ProjectActivity

Processing

of feed

CO2 Yes Main emission source. CO2 is produced in the reforming

of the feed and may be partially recovered for the

production of ammonia . CO2 in excess of that required

for ammonia, if any, is released into atmosphere.

CH4 No Negligible fugitive CH4 emissions may occur during the

processing of the feed. These emissions (if any) would be

essentially the same as in the baseline scenario.

Therefore, they are excluded for simplification.

N2O No Not applicable

Fuel used in

furnaces

(thermal

energy)

CO2 Yes Main emission source due to the combustion of fossil

fuels. The project activity may result in lower thermal

energy required, Any CO2 recovered from flue gasesresulting from combustion of fossil fuel is deducted from

this emission source.

CH4 No These emissions are expected to be the same or lower as

compared to the baseline scenario.

N2O No These emissions are expected to be the same or lower as


Fuel used in

boilers

(Steam and

Power

generation)

CO2 Yes Main emission source.

CH4 No These emissions are expected to be the same or lower as




Grid

Electricity

requirement

CO2 Yes Main emission source.CH4 No These emissions are expected to be the same or lower as





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B.4. Description of how the baseline scenario is identified and description of the identified

baseline scenario:

>> Selection of Baseline scenario

The methodology applicable in case of the proposed CDM project is AM 0050 Version XX. The

approved methodology specifies the use of combined tool for identification of baseline scenario and

demonstrate additionality.

Accordingly the baseline scenario has been identified as per the provisions in the approved methodology

and the combined tool for identification of baseline scenario and demonstrates additionality.

The various alternatives to the CDM project activity, identified are as under:

Alternative 1: The continuation of current practice, i.e. usage of hydrocarbon feedstock / fuel with higheremission intensity and / or continuation of the present process technology for the production of ammonia /

ammonia derivatives ,

Alternative 2: Partial substitution of hydrocarbon feedstock / fuel with higher emission intensity with NG

for similar output of ammonia

Alternative 3: Complete switchover from hydrocarbon feedstock / fuel with higher emission intensity to

NG

Alternative 4: Usage of hydrocarbon feedstock / fuel with higher emission intensity as feed and

production of CO2 surpluses, but with capture of the CO2 surpluses.

All the four alternatives given above are in compliance with the applicable laws and regulations.Among the various alternatives given above, Alternative 4 cannot be a probable baseline scenario as this

is not a general industrial practice as well as there is no facility at NFL Panipat plant to capture the CO2

surpluses for its use in other applications further there is no opportunity to use captured CO2. Hence it

has been excluded from further analysis.

Alternative 2 cannot be the alternative scenario because the technology involved in heavy oil as feed stock

and Natural gas as feed stock is entirely different and the hybrid two hydrocarbon stocks cannot be used

as feed stock due to technological limitations.

Among Alternative 1, 3 there is no investment required for alternative 1 and it also does not faces any

financial barriers as explained in the subsequent sections hence alternative 1 i.e continuation of current

practice of using heavy oil as feed stock and support fuel is the baseline scenario to the project activity.

B.5. Description of how the anthropogenic emissions of GHG by sources are reduced below

those that would have occurred in the absence of the registered CDM project activity (assessment

and demonstration of additionality):

>> Additonality


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The current version of the approved methodology AM 0050 Version XX asks for the use of combined

tool to determine the baseline and demonstrate additionality. Further the current version of the

methodology mandates the use of benchmark investment analysis to demonstrate additionality.

In 1977 Government of India introduced Retention Pricing Scheme (RPS) to provide urea to the farmers

at affordable price and also make the fertilizer business sustainable. Under this scheme, different

manufacturers of Urea are provided a subsidy by the government of India to cover the difference of the

cost of production (plus a predetermined profit margin) and the administered sales price. As the cost of

production in different units producing urea is different (due to difference in technology, scale of

operation, difference in the feed stock used, difference in the norms of consumption of feed and fuel,

etc.) the extent of subsidy (in terms of per ton of Urea produced) to different units for producing urea is

different. The annual subsidy bill on account of this being footed by the government is quite huge. A

circular by government of India in this regard has specified the policy of Government of India to provide

incentives to the producers of Urea who switch from Oil/Naphtha to Natural Gas Feedstock . From the

above the following is evident:

The very reason that the government of India had to provide fiscal incentives for implementationof the feed switch project clearly demonstrates that such projects are not commercially viable at

their own for the producers of urea.

Promotion of feed switch from naphtha / oil to gas for urea production is a policy for the

government. It is not a regulatory directive by the government.

As is clear Urea manufacturing is not commercially viable under current market conditions and the

Indian Government has to subsidize this activity.

In the proposed CDM project the ground for project additionality originates from the fact that the project

activity requires complete replacement of some sections of the existing plant and equipment with the new

ones. This is in spite of the remaining lifetime of the equipment being replaced.

Apart from this revenue government will also give subsidy to NFL in the way of special fixed cost. Due

to the high capital cost for implementing the proposed project activity the return on the capital deployed

is not adequate

To summarize this, the following benefits would be available to NFL.

As there is no substantial gain to fertilizers plants in return of huge capital investment being borne by the

fertilizers plant. Government of India has will also be providing the capital subsidy to fertilizer plants in

terms of special fixed cost.

The components of special fixed cost would be as follows:

1. Reimbursement of capital cost to fertilizer plant in five years from the date of commissioning

2. Reimbursement of interest on borrowed capital in five years from the date of commissioning

All these revenue streams has been taken for the computation of financials and the results of these

computations are shown in subsequent Paragraphs.

The methodology follows for the demonstration of additionality as per the latest version of combined

tool to identify baseline and demonstrate additionality is as follows:


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Step 3b: Calculation of the suitable financial Indicator

Detailed calculations considering all the revenue and cost streams have been done and internal rate ofreturn has been computed based on the entire investment and anticipated revenues.

The results of the calculations are as shown below:

IRR % without CDM revenue

IRR of the CDM Project activity 5.45%

IRR % with CDM revenue


It can be clearly analysed that the project has the IRR of 5.45% which is below the Benchmark PLR of

RBI and the project crosses the hurdle of the benchmark only after taking into account the CDM revenue.

Step3c: Sensitivity Analysis

A detailed sensitivity analysis was also carried out for the dominant contributors and following results

were obtained.

Sensitivity on 10% decrease in capital cost

The results of the calculations are as shown below:

IRR % without CDM revenue


IRR % with CDM revenue


It is clear that in-spite of 10% decrease in capital cost the IRR does not crosses the hurdle rate and hence

project activity clears the sensitivity test.

Step 4:Common practice analysis

In India, there are four plants which are being operated on furnace oil as feed stock. It includes three

plants from NFL Panipat, Bathinda and Nangal and Gujarat Naramda Valley Fertilizer Plant. This

changeover will involve a complete technological shift as the technologies involved with heavy oil and

natural gas are entirely different and involves major modifications/changes in the front end section of

ammonia plant. The similar exercise is also been done by Gujarat Naramda Valley Fertilizer Plant and

they have also gone for the CDM route. This analysis clearly indicates that all the similar activities

happening across the regions are opting for CDM and hence it is not a common practice.

The project activity satisfies all four steps as defined in combined tool for identification of Baseline and

demonstrate addtionality are fulfilled and hence project is additional

B.6. Emission reductions:


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procedures actually

applied :

Any comment: Computed once at the start of the crediting period and kept fixed throughout thecrediting period

Parameter: QFeed, Hist

Data unit: (in tons Per Year)

Description: Historical quantity of feed stock used for production of ammonia / ammonia

derivative

Source of data: Obtained from data logs, measurements and plant records at the project site

Value Applied 244205

Justification of the

choice of data or

description of

measurement

methods and

procedures actually

applied :

Computed based on historical production of ammonia / ammonia derivative, three

years prior to the start of the project activity

Any comment: Computed once at the start of the crediting period and kept fixed throughout the

crediting period

Parameter: BEFFeed,Hist

Data unit: (in tCO2)

Description: Emission factor for the feedstock used in the baseline (Quantity of CO2 that would be

produced from the feedstock per ton of feedstock)

Source of data: Obtained from data logs, measurements and plant records at the project site

Value applied 3.16

Measurementprocedures (if any):

Computed from the net calorific value of the feedstock and the emission factor of thefeedstock

Any comment: Although in this case the hydrocarbon is used as a feedstock and not as a fuel, it is

considered that the emission of CO2 is related to the NCV in the same manner as in

the case of use as a fuel.

Parameter: EFFeed,

Data unit: (in tonCO2/TJ)

Description: CO2 emission factor of the feedstock used prior to the implementation of the project

activity in the yearX

Source of data: IPCC default values at the lower limit of the uncertainty at a 95% confidence

interval as provided in table 1.4 of chapter 1 of Vol. 2 (Energy) of the 2006 IPCC

Guidelines on National GHG InventoriesValue Applied 77.4


choice of data or

description of

measurement

methods and

For (a) and (b): Measurements should be undertaken in line with national or

international fuel standards


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procedures actually

applied

Any comment:

Parameter: NCV Feed,

Data unit: (TJ / Ton of feedstock)

Description: Net caloric value of the feedstock used prior to the implementation of the project

activity in the year X

Source of data: The following data sources may be used if the relevant conditions apply:

Data source Conditions for using the data source

Values provided by the feedstock in

invoices

Regional or national average default

values

If values are reliable and

documented in regional or national

energy statistics / energy balances

IPCC default values at the lower

limit of the uncertainty at a 95%

confidence interval as provided in

Table 1.2 of Chapter 1 of Vol. 2

(Energy) of the 2006 IPCC

Guidelines on National GHG

Inventories

If above two data source is not

available.

Value Applied 0.041Justification of the

choice of data or

description of

measurement

methods and

procedures actually

applied

Any comment:

Parameter: QHeat, Hist Data unit: (in tons)

Description: Historical quantity of fossil fuel used in the furnaces for production of ammonia /ammonia derivative

Source of data: Obtained from the data logs, measurements and plant records at project site

Value Applied: 0


choice of data or

description of

Computed based on historical consumption of fossil fuels used in the furnaces three

years prior to the start of the project activity


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measurement

methods and

procedures actuallyapplied

Any comment:

Parameter: EFheat,iData unit: (in tCO2)

Description: Emission factor for the fossil fuel used in the baseline (Quantity of CO2 that would

be produced per ton of fuel)



(a) Values provided by the fuelsupplier in invoices

This is the preferred source

(b) measurements by the project

participants

Applicable if (a) is not available

(c) Regional or national default

values

These sources can only be used for

liquid fuels and should be based on

well-documented, reliable sources

(such as national energy balances)

(d) IPCC default values at the

lower limit of the uncertainty

at a 95% confidence interval

as provided in table 1.4 ofchapter 1 of Vol. 2 (Energy)

of the 2006 IPCC Guidelines

on National GHG Inventories.

If (a) is not available

Value Applied 0

Measurement

procedures (if any):



Any comment: For (a): If the fuel supplier does provide the NCV value and the CO2 emission factor

on the invoice and these two values are based on measurements for this specific fuel,

this CO2 factor should be used. If another source for the CO2 emission factor is used

or no CO2 emission factor is provided, Options (b), (c) or (d) should be used

Parameter: NCVHeat,iData unit: (TJ / Ton of fuel)

Description: Net caloric value of the fossil fuel used in the furnaces prior to the implementation of

the project activity in the year X



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Parameter: EFUtility coal

Data unit: (in tCO2/TJ)Description: Emission factor for the coal used in the boilers in the baseline (Quantity of CO2 that

would be produced per ton of fuel)



Guidelines on National GHG Inventories

Value Applied: 96.1


choice of data or

description of

measurement

methods and

procedures actually

applied



Any comment:

Parameter: EFUtility FO,Data unit: (in tCO2/TJ)

Description: Emission factor for the fossil fuel used in the boilers in the baseline (Quantity of CO2

that would be produced per ton of fuel)



Guidelines on National GHG Inventories

Value Applied: 77.4


choice of data ordescription of

measurement

methods and

procedures actually

applied



Any comment: For (a): If the fuel supplier does provide the NCV value and the CO2 emission factor

on the invoice and these two values are based on measurements for this specific fuel,

this CO2 factor should be used. If another source for the CO2 emission factor is used

or no CO2 emission factor is provided, Options (b), (c) or (d) should be used

Parameter: NCVUtility coal

Data unit: (TJ / Ton of fuel)Description: Net caloric value of the fossil fuel used in the boilers prior to the implementation of






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invoices


values


documented in regional or nationalenergy statistics / energy balances






Guidelines on National GHG

Inventories


available.

Value Applied: 0.017


choice of data or

description ofmeasurement

methods and

procedures actually

applied

Any comment:

Parameter: NCVUtility FOData unit: (TJ / Ton of fuel)

Description: Net caloric value of the fossil fuel used in the boilers prior to the implementation of





invoices


values


documented in regional or national

energy statistics / energy balances






Guidelines on National GHGInventories


available.



choice of data or

description of


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= 295751 MT per Year

Baseline Emissions due to the use of feed (BEFeed,Hist)

The emissions due to the use of hydrocarbon feedstock for the production of ammonia / ammonia

derivative are calculated as follows:

HistFeedHistFeedHistFeed BEFQBE ,, *,=

Where:

QFeed, Hist Historical quantity of feed stock used for production of ammonia / ammonia

derivative (in tons)

BEFFeed,Hist Emission factor for the feedstock used in the baseline (Quantity of CO2 that would

be produced from the feedstock per ton of feedstock) (in tCO2)

HistFeedBE , = (244205 tonnes of feed stock per Year * 3.16 tCO2/tonne of feed stock)

= 771436 tCO2/Year

),,.( 1,1,,, = xFeedxFeedxFeedHistFeed BEFBEFBEFMinBEF

Where:

BEFFeed,x = Average CO2 emission factor for the feedstock used prior to the implementation of the

project activity in the yearx (in tons per ton of feedstock)

3

3

1

,,

,

=

=x

xHistFeed

HistFeed

Q

Q

Where:

QFeed,Hist = Historical quantity of feedstock used (in tons)

QFeed, Hist,-x = Quantity of feedstock used prior to the implementation of the project activity in yearx

(in tons)

Emission Factor for the feedstock (BEFFeed) is calculated as

HistFeedQ , = 30.834 tonnes per hour * 24 hrs/day * 330 days/year

= 244205 MT per Year

XFeedXFeedXFeed EFNCVBEF = ,,, *

Where:


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EFFeed, -X CO2 emission factor of the feedstock used prior to the implementation of the project

activity in the yearX(in tonCO2/TJ)

NCV Feed,-X Net calorific value of the feedstock used prior to the implementation of the project

activity in the year X (TJ / Ton of feedstock)

XFeedBEF , = 77.4tCO2/TJ x 0.041 TJ/tonne of feed stock

= 3.16 tCO2/tonne of feed stock

Baseline Emissions due to the thermal energy used in the furnaces (BEHeat,y)

Baseline CO2 emissions from thermal energy are calculated as follows:

iheatiHeatHistiHeat

n

iHistHeatEFNCVQBE ,,,,, **=

Where:

QHeat i, HistAnnual average Historical quantity of fossil fuel i used in the furnaces for

production of ammonia (in tons)

NCVi,heat

iheatEF ,

Net Calorific value of fossil fuel i used for thermal energy in the furnaces(in

TJ/tonne)

CO2 Emission factor for the fossil fuel i(in tCO2)

3

3

1

,,,

,,

=

=x

xHistiHeat

HistiHeat

Q

Q

Where:

QHeat,i,, Hist,-x = Quantity of feedstock type I used prior to the implementation of the project activity in

yearx (in tons)

QHeat,iHist = 0 tonnes

HistHeatBE , = 0 tCO2/Year

Baseline Emissions due to use of fossil fuel in the Boilers (BEUtility,)

Baseline CO2 emissions due to the use of fossil fuel in the boilers for the process steam and power arecalculated as follows:

3

** ,,,,,,

3

1,

=

=

n

i

xiutilityxiutilityxiutility

xHistUtility

EFNCVQ

BE


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Where:

xiutility

Q

,,

Historical quantity of fossil fuel i used in the boilers for production of steam

and power (in tonne per year) in the year x before the year of project activity,x

xiutilityNCV ,,

xiutilityEF ,,

Net calorific value of fossil fuel i used (TJ/Tonne)

CO2 Emission factor for the fossil fuel i (in tCO2/TJ)

HistUtilityBE , = (67.972 tonnes per hour x 330 days in Year x 24 hrs/day x 1.67 tCO2/tonne of coal)+ (4.179 tonnes per hour x 330 days in Year x 24 hrs/day x 3.16 tCO2/tonne of FO)

= 1003278 tCO2/Year

Baseline Emissions due to use of grid electricity (BEGrid,)

Baseline CO2 emissions due to the use of fossil fuel in the boilers for the process steam and power are

calculated as follows:

HistGridHistGridHistGrid BEFQBE ,, *,=

Where:

QGrid, Hist Historical quantity of power imported from the grid (in MWh)

BEFGrid,Hist Baseline emission factor for the power imported from the grid (in tCO2 /MWh)

HistUtilityBE , = (67.972 tonnes per hr * 24 hrs per day * 330 days per year *1.67tCO2/tonne of coal)+(4.179 kNM3/hr * 24 hrs per day *330 days per

year * 3.1667tCO2/tonne of heavy oil)= 1003278 tCO2/year

3

3

1

,,

,,

=

= xxHistUtility

HistiUtility

Q

Q

Where:

QUtility, Hist,-x = Historical quantity of fossil fuel i used in the boilers for production of steam and

power (in tonne per year) in the year x before the year of project activity ,x


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),,.( 2,1,,,

= xGridxGridxGridHistGrid

EFBEEFMinBEF

Where:

BEFGrid,x = Historical CO2 emission factor for power imported from the grid (in tCO2 / MWh))

EFGrid,X = Emission factor of the grid from which the power is imported (in tCO2 / MWh). This

is computed using the latest version of the Tool for determination of emissions from

an electrical system

3

3

1

,,

,

=

= xxHistGrid

HistGridy

Q

Q

Where:

QGrid,Hist = Historical quantum of power imported from the grid (MWH)QGrid, Hist,-x = Quantum of power imported prior to the implementation of the project activity in year

x (in MWh)

HistGridyQ , = 13615 MWh

HistGridBE , = 13615 MWh x 0.8 tCO2/MWh

` = 10892 tCO2/year

For the determination of emission factors of the fuels and the feedstock, guidance from the 2006 IPCC

Guidelines for National Greenhouse Gas Inventories has been followed where appropriate

Project Emissions

Project activity emissions are calculated as follows:

yGridyUtilityyHeatyFeedy PEPEPEPEPE ,,,, +++=

Where:

PEFeed,y Emissions due to the use of feedstock for the production of ammonia / ammonia derivative in

each year Y of the crediting period,(in tCO2)

PEHeat,y Emissions due to the production of thermal energy used in the furnaces (feed treatment and

reforming) after deducting the CO2 recovered by the CDR plant (if any) in each year y of the

crediting period, in tCO2.

PEUtility,y Emissions due to use of fossil fuels in the boilers for onsite production of steam and power in

each year y of the crediting period, in tCO2.

PEGrid,y Emissions due to import/ export of power from the grid in the year y of the crediting period

(in tCO2)


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For determination of emission factors, guidance from the 2006 IPCC Guidelines for National Greenhouse

Gas Inventories has been followed where appropriate.

yHeatPE , = 6.154kNM3/hr * 24hrs/day *330 days/year*0.036TJ/NM3*56.1tCO2/TJ

= 98160 tCO2/Year

Emissions due to use of fossil fuels in the boilers (PEUtility,y)

Emissions due to the production of thermal energy used in the furnaces (feed treatment and reforming) are

calculated as follows:

YiutilityPJCO

i

YiutilityYiUtilityYUtility EFNCVFCPE ,,,,2,,,,, =

yUtilityPE , = (47.314T/hr *24 hrs/day *330days/year*1.67tCO2/tonne of fuel) + (3.242*24 hrs/day

*330days/year*2.01tCO2/tonne of NG)

= 677289 tCO2/Year

Where:

FCUtility,i,Y Quantity of fuel type i consumed in the boilers of the power plant for producing power and

steam in year y of the crediting period, in mass or volume units.

NCVi,Y Net calorific value of fuel type i in each year y of the crediting period, in (TJ/mass or volume

units.)

EFCO2,PJ,utility

,,i,Y

CO2 emission factor of the fuel type i used in the boilers of the power plant in the year y of

the crediting period, (in tCO2/TJ).

For determination of emission factors, guidance from the 2006 IPCC Guidelines for National Greenhouse

Gas Inventories has been followed where appropriate.

Emissions due to import / export of power from the grid (PEGrid,y)

The emissions / emission reductions due to import / export of power from the grid can be computed as

follows:

YGridYPRGridYGrid EFQPE ,,,, =

Where:

QGrid,PR,Y, Quantum of electricity imported from the grid in the year y of the crediting period, in MWh.

EFGrid,Y CO2 emission factor for the power from the grid in the year y of the crediting period, in

tCO2/MWh.

EFgrid,Y, is the emission factor of the grid that must be calculated as the generation-weighted average

emissions per electricity unit of all generating sources serving the system.


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Any comment: Volumetric units should be at normal pressure and temperature

Data / Parameter: QGrid,PR,yData unit: MWh

Value Applied: 13615

Description: Quantity of electricity obtained from / supplied to the grid by the project activity

during each year y of the crediting period. Measured at the project site.

Source of data: Measured in the project activity by digital control systems and/or data logs.

Measurement


Electrical Energy Meter

Monitoring frequency: Continuously

QA/QC procedures: Electrical Energy Meter used for measurement should be calibrated regularly as

per ISO procedures or according to manufacturers guidelines

Any comment: In case of net export of power to the grid. Negative sign will be used

Data / Parameter: FCUtility coal, y

Data unit: Tonnes Per Year

Description: Quantity of fuel type i consumed in the boilers of the power plant generation of

steam and power in each year y of the crediting period.


Source of data: On-site measurements

Measurement


Flow-rate meters


QA/QC procedures: Meters should be calibrated regularly according to manufacturers guidelines.


Data / Parameter: FCUtility Natural Gas, y

Data unit: kNM3 Per Year

Description: Quantity of fuel type i consumed in the boilers of the power plant generation of

steam and power in each year y of the crediting period.


Source of data: On-site measurements

Measurement


Flow-rate meters


QA/QC procedures: Meters should be calibrated regularly according to manufacturers guidelines.


Parameter: NCVcoal,yData unit: TJ/tonnes of coal

Description: Average net calorific value of coal in year y of the crediting period.


Source of data: IPCC Guidelines for National Greenhouse Gas Inventories.

Measurement


-


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Monitoring frequency

QA/QC procedures -

Any comment: -

Parameter: CV G,y

Data unit: TJ/NM3 of NG

Description: Average net calorific value of fuel type i and NG/LNG respectively, in year y of

the crediting period.


Source of data: IPCC Guidelines for National Greenhouse Gas Inventories.

Measurement


-

Monitoring frequency

QA/QC procedures -

Any comment: -

Data / Parameter: EFCO2, PJ coal i,y

Data unit: tCO2/TJ

Description: CO2 emission factor of fuel type i used for steam generation in the boilers in the

year y.

Value Applied: 96.1

Source of data: IPCC Default Values

Measurement


Monitoring frequency: Yearly

QA/QC procedures:

Any comment:

Data / Parameter: EFCO2, PJ Natural Gas i,y

Data unit: tCO2/TJ

Description: CO2 emission factor of fuel type i used for steam generation in the boilers in the

year y.

Value Applied: 56.1

Source of data: IPCC default values

Measurement



QA/QC procedures:

Data / Parameter: QGrid,PR,y

Data unit: MWh


Description: Quantity of electricity obtained from the grid by the project activity during each

year y of the crediting period. Measured at the project site.

Source of data: Measured in the project activity by digital control systems and/or data logs.


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Measurement


Electrical Energy Meter

Monitoring frequency: ContinuouslyQA/QC procedures: Electrical Energy Meter used for measurement should be calibrated regularly as

per ISO procedures or according to manufacturers guidelines

Any comment:

Data / Parameter: EFgrid,y

Data unit: tCO2/MWh

Value Applied: 0.80

Description: CO2 emission factor for grid electricity during the yeary.

Source of data: Use the latest approved version of Tool to calculate emission factor for an

electricity system to calculate the grid emission factor.

Measurement


-

Monitoring frequency: Either once at the start of the project activity or updated annually, consistent

with guidance in Tool to calculate emission factor for an electricity system.

QA/QC procedures: Apply procedures as in Tool to calculate emission factor for an electricity

system

Any comment: All data and parameters to determine the grid electricity emission factor, as

required by Tool to calculate emission factor for an electricity system, shall

be included in the monitoring plan.

Any comment:

Data / Parameter: EFCO2,upstream,LNG,y

Data unit: tCO2/TJ

Description: Emission factor for upstream CO2 emissions due to fossil fuel combustion /

electricity consumption associated with the liquefaction, transportation, re-gasification and compression of LNG into a natural gas transmission or

distribution system in year y.

Value Applied: 6

Source of data: Default Value given in the methodology

Measurement


Where reliable and accurate data on upstream CO2 emissions due to fossil fuel

combustion / electricity consumption associated with the liquefaction,

transportation, re-gasification and compression of LNG into a natural gas

transmission or distribution system is available, project participants should use

this data to determine an average emission factor. Where such data is not

available, project participants may assume a default value of 6 tCO2/TJ as a

rough approximation2.


2This value has been derived on data published for North American LNG systems. Barclay, M. and N. Denton,

2005. Selecting offshore LNG process. http://www.fwc.com/publications/tech_papers/files/LNJ091105p34-36.pdf

(10th April 2006).


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The unit head is responsible for the overall functioning and maintenance of the project activity. The Shift

operator maintains all the data records and ensures the completeness and reliability of the data. The ShiftIn-charge maintains a day to day power generation log. The monitoring reports are checked periodically

by the Plant In-charge and discussed thoroughly with the data monitoring personnel. Corrective action is

taken immediately if any improper functioning or operation problem with the equipment is observed. The

archived data shall be kept for two years after the crediting period or issuance of CERs.

After verification of the data and due diligence on the correctness if required, an annual report on

monitoring and estimations shall be maintained by the CDM team and record to this effect shall be

maintained for verification.

QA & QC Procedures to be followed

Necessary check meters as required would be installed, to operate in standby mode or when the main

meters are not working. All meters will be calibrated and sealed as per industry practices at regularintervals. Records of calibration certificates will be maintained for verification. Hence, high quality is

ensured with the above parameters.

B.8. Date of completion of the application of the baseline study and monitoring methodology

and the name of the responsible person(s)/entity(ies):

>> The date of completion of baseline and monitoring methodology is 31/07/2011. Contact details of the

person responsible for development of baseline and monitoring methodology is given below

Mr. K.K. Goel

National Fertilizers Limited

A-11 Sector 24

NOIDA, Uttar Pradesh201301

E-mail: [email protected]

SECTION C. Duration of the project activity / crediting period

C.1. Duration of the project activity:

C.1.1. Starting date of the project activity:

>> 29th January 2010

C.1.2. Expected operational lifetime of the project activity:

>> 20 Years


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Annex 1

CONTACT INFORMATION ON PARTICIPANTS IN THE PROJECT ACTIVITY

Organization: National Fertilizers Limited

Street/P.O.Box: Sector 24

Building: A-11

City: NOIDA

State/Region: Uttar Pradesh

Postcode/ZIP: 201301

Country: India

Telephone: 0120-2412383

FAX: 0120-2412384

E-Mail: [email protected]

URL: www.nationalfertilizers.comRepresented by: -

Title: Chief Manager Mechanical

Salutation: Mr.

Last name: Goel

Middle name: -

First name: K.K

Department: Technical Department

Mobile: +919910575722

Direct FAX: +911202412397

Direct tel: +911202412294

Personal e-mail: [email protected]


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Annex 2

INFORMATION REGARDING PUBLIC FUNDING


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Annex 3

BASELINE INFORMATION

Annex 4

MONITORING INFORMATION

- - - - -

Documents

NFL Panipat PDD_ 25 Oct- 2011