AXIA ENERGIA COGENERATION PROJECT IN UNIBOL

Transcription

PROJECT DESCRIPTION: VCS Version 3
AXIA ENERGIA COGENERATION
PROJECT IN UNIBOL
AXIA ENERGÍA S.A.S.
Calle 77 B No. 57-141
Barranquilla – Colombia
Project Title
Version
Date of Issue
Prepared By
Contact
v3.2
AXIA Energia Cogeneration Project in Unibol
02
16-February-2015
Christian Ehrat
Independent Consultant
Christian Ehrat
Climate Change &
Sustainability Consultant
Calle 6 No. 32-61
Medellin - Colombia
Tel. (+57) 317 575 0481
Email: [email protected]
1
Table of Contents
1 Project Details ........................................................................................................................................ 3 1.1 Summary Description of the Project ............................................................................................... 3 1.2 Sectoral Scope and Project Type ................................................................................................... 4 1.3 Project Proponent ........................................................................................................................... 4 1.4 Other Entities Involved in the Project .............................................................................................. 4 1.5 Project Start Date............................................................................................................................ 4 1.6 Project Crediting Period .................................................................................................................. 5 1.7 Project Scale and Estimated GHG Emission Reductions or Removals .......................................... 5 1.8 Description of the Project Activity ................................................................................................... 5 1.9 Project Location .............................................................................................................................. 7 1.10 Conditions Prior to Project Initiation ............................................................................................... 7 1.11 Compliance with Laws, Statutes and Other Regulatory Frameworks ............................................ 8 1.12 Ownership and Other Programs ..................................................................................................... 9 1.12.1 Right of Use ........................................................................................................................... 9 1.12.2 Emissions Trading Programs and Other Binding Limits ........................................................ 9 1.12.3 Other Forms of Environmental Credit .................................................................................... 9 1.12.4 Participation under Other GHG Programs ........................................................................... 10 1.12.5 Projects Rejected by Other GHG Programs ........................................................................ 10 1.13 Additional Information Relevant to the Project ............................................................................. 10 2 Application of Methodology .................................................................................................................. 10 2.1 Title and Reference of Methodology ............................................................................................. 10 2.2 Applicability of Methodology ......................................................................................................... 11 2.3 Project Boundary .......................................................................................................................... 12 2.4 Baseline Scenario ......................................................................................................................... 14 2.5 Additionality................................................................................................................................... 15 2.6 Methodology Deviations................................................................................................................ 20 3 Quantification of GHG Emission Reductions and Removals ............................................................... 20 3.1 Baseline Emissions ....................................................................................................................... 20 3.2 Project Emissions ......................................................................................................................... 26 3.3 Leakage ........................................................................................................................................ 27 3.4 Net GHG Emission Reductions and Removals............................................................................. 27 4 Monitoring ............................................................................................................................................ 28 4.1 Data and Parameters Available at Validation ............................................................................... 28 4.2 Data and Parameters Monitored ................................................................................................... 30 4.3 Monitoring Plan ............................................................................................................................. 31 5 Environmental Impact .......................................................................................................................... 33 6 Stakeholder Comments ........................................................................................................................ 33 v3.2
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1
PROJECT DETAILS
1.1
Sum m ary Description of the Project
The AXIA Energia Cogeneration Project in Unibol (in the following, the project activity or the projec) will
be implemented by the company AXIA Energía S.A.S.
The project activity consists of the implementation and operation of a cogeneration plant to deliver electric
and thermal energy to the paper manufacturing plant of the company Fábrica de Bolsas de Papel Unibol
S.A. (in the following Unibol), located in the municipality of Soledad in the Department of Atlántico,
Colombia.
Previously of the cogeneration project implementation, the paper manufacturing plant generates electric
and thermal energy that is required for the manufacturing process with its own equipment with lower
efficiency, including two natural gas based electric generators with 1750 kilowatts (kW) each and two heat
recovery steam boilers. Besides, a natural gas boiler and a secondary coal boiler are operated to cover
the additional steam requirement; and some electric energy is consumed partially from the grid.
The new project aims at installing and operating a new cogeneration plant with increased efficiency that
allows reducing the natural gas consumption and avoids coal consumption; thus it contributes to reduce
Greenhouse Gas (GHG) emissions associated with the combustion processes.
This new cogeneration plant will be installed by AXIA Energia S.A.S., which will also be the owner of the
equipment and will be in charge of operation and maintenance. The electric and thermal energy
generated will be delivered and sold to the paper manufacturing plant of Unibol at a previously
established tariff. In case the manufacturing plants presents low consumption, the excess power may be
delivered to the National Interconnected System-SIN (in Spanish: Sistema Interconectado Nacional).
The main equipment of the cogeneration plant consists of a high-efficiency natural gas based power
generator with a capacity of 6,700 kW and a heat recovery steam boiler that utilizes the waste energy of
the power generator to produce 6,000 lbs/hr of steam. Besides, the natural gas boiler will continue
operation to cover the difference between the required process steam and the steam produced with the
new boilers.
As a result of the implementation of the new cogeneration project, GHG emissions will be reduced by
approximately 9,817 tCO2 per year (see details in section 3).
Besides, the project contributes to the country´s sustainable development in the following manner:
•
•
•
•
v3.2
The project will decrease emissions of sulphur oxides (SOx), nitrogen oxides (NOx), carbon
monoxide, particulate matter, other pollutants, as well as carbon dioxide associated with the
combustion of coal and natural gas.
The project will reduce the consumption of fossil fuels that are non-renewable and limited for use.
The project is not a common practice and has a innovative character, since it uses high-efficiency
equipment. This will help to replicate and diffuse similar activities in the industrial sectors in
Colombia.
The technology transfer allows propagating capacities in the manufacturing sector in the region.
3
1.2
Sectoral Scope and Project Type
Scope 4 - Manufacturing industries
The project consists of the implementation of a cogeneration plant. It is not a grouped project.
1.3
Project Proponent
The project proponent is AXIA Energía S.A.S,, which will be responsible for the construction, operation
and maintenance of the project.
Organization name
AXIA Energía S.A.S.
Contact person
Juan Guillermo Arroyave
Title
Manager
Address
AXIA ENERGÍA S.A.S.
Calle 77 B No. 57-141
Barranquilla – Colombia
1.4
Telephone
Tel. (+575) 368 92 22
Email
[email protected]
Other Entities Involved in the Project
Organization name
-
Role in the project
Consultant for project development
Contact person
Christian Ehrat
Project Developer / Independent Consultant
Title
Climate Change and Sustainability Consultant
Address
Calle 6 No. 32-61
Edificio Altos de Provenza 401
Medellin - Colombia
1.5
Telephone
(+57) 317 575 0481
Email
[email protected]
Project Start Date
The project is expected to be operational on 01/07/2015, which will be the project start date. This will be
adjusted in accordance with real operational start.
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1.6
Project Crediting Period
The first crediting period is 10 years, from 01/07/2015 to 31/06/2025.
1.7
Project Scale and Estim ated GHG Em ission Reductions or Rem ovals
Project Scale
Project
x
Large project
Year
Estimated GHG emission
reductions or removals
(tCO2e)
31/07 – 31/12/2015
4,908
01/01 – 31/12/2016
9,817
01/01 – 31/12/2017
9,817
01/01 – 31/12/2018
9,817
01/01 – 31/12/2019
9,817
01/01 – 31/12/2020
9,817
01/01 – 31/12/2021
9,817
01/01 – 31/12/2022
9,817
01/01 – 31/12/2023
9,817
01/01 – 31/12/2024
9,817
01/01 – 30/06/2025
4,908
Total estimated ERs
Total number of crediting years
Average annual ERs
1.8
98,170
10
98,170
Description of the Project Activity
The project activity consists of the implementation and operation of a cogeneration plant to deliver electric
and thermal energy to the paper manufacturing plant of the company Fábrica de Bolsas de Papel Unibol
S.A. (in the following Unibol), located in the municipality of Soledad in the Department of Atlántico,
Colombia.
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Fábrica de Bolsas de Papel Unibol S.A. is an industrial company dedicated to the manufacturing and
commercialization of paper products such as Kraft paper, paper bags, toilet paper, napkins, kitchen paper
and envelopes. The manufacturing process requires electric and thermal energy, currently around
2,7 GWhel per month and 12,600 lbs/hr (pounds of steam per hour). Currently, this energy demand is
attended with the following equipment:
ü
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ü
Two (2) natural gas based power generators with 1,750 kW each and an efficiency of about
28%
Two (2) heat recovery steam boilers with a generation capacity of 1,500 lbs/hr
One (1) natural gas boiler with a steam generation capacity of 20,700 lbs/hr that generates
the difference between the steam generated by the two heat recovery boilers and the total
steam demand together with the coal-fired boiler below
One (1) coal-fired boiler with a steam generation capacity of 20,700 lbs/hr that generates the
difference between the steam generated by the two heat recovery boilers and the total steam
demand together with the natural gas boiler
Besides, electric energy from the grid is consumed to cover the demand of the manufacturing
process (i.e. the amount of electric energy that cannot be delivered by the two generators).
The new project aims at installing and operating a new cogeneration plant with increased efficiency to
deliver electric and thermal energy to the manufacturing process of Unibol, as well as reducing GHG
emissions associated with the combustion process of natural gas and coal. This project will basically
replace the two previously installed power generators and heat recovery boilers, with a more efficient
cogeneration system, thus reducing natural gas consumption for power generation and in the steam
boiler, while achieving the same output. Additionally, it will avoid coal-based generation as well as the
power consumption from the grid. Grid electricity and coal will be consumed during maintenance or
shutdowns only and are not considered due to the small amounts. It is important to take into account that
the old equipment was installed in in 2004 and 2010, and thus due to the lifetime of over 25 years of such
equipment would not require any replacement.
This new cogeneration plant will be installed by AXIA Energía S.A.S., which will also be the owner of the
equipment and will be in charge of operation and maintenance. The electric and thermal energy
generated will be delivered and sold to the paper manufacturing plant of Unibol at a previously
established tariff. In case the manufacturing plants presents low consumption, the excess power may be
delivered to the National Interconnected System-SIN (in Spanish: Sistema Interconectado Nacional).
The main equipment of the cogeneration plant consist of a high-efficiency natural gas based power
generator with a capacity of 6,700 kW and a heat recovery steam boiler that utilizes the waste energy of
the power generator to produce 6,000 lbs/hr of steam. Besides, the natural gas boiler will continue
operation to cover the difference between the required process steam and the steam produced with the
new boilers.
In order to attend the power demand, an internal combustion engine is used for the cogeneration system,
with the following specifications:
Table 1: Technical specifications of the power generator.
Brand
Hyundai
Model
14H35/40GV
No. of cylinders
14
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Capacity
Voltage
Frequency
Efficiency
Equipment included
6,700 kW
13,8 kV
60 Hz
46,3%
• Gas pressure regulation unit
• Oil cooling unit
• Cooling radiator with expansion tank
• Air compressor unit for start up
• Exhaust gas pipes and silencer
• Control panel for motor and generator
The heat recovery steam boiler that will use the waste energy from the exhaust gases of the generator
will have a capacity of 6,000 lbs/hr.
1.9
Project Location
The project activity is implemented within the paper manufacturing plant of the company Fábrica de
Bolsas de Papel Unibol S.A. (in the following Unibol), located in the municipality of Soledad in the
Department of Atlántico, Colombia. (However, please take into account that the project owner is AXA
Energía S.A.S. who will own and operate the equipment and sell the energy to the manufacturing process
at a specific tariff.)
The coordinates of the project location are 1696915.7 North and W 924454.9 East (MAGNA-SIRGAS,
Bogotá).
1.10
Conditions Prior to Project Initiation
Prior to the project implementation, the electric and thermal energy required for the manufacturing
process is generated wit the following equipment:
ü
ü
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28%
It is important to take into account that the old equipment was installed in in 2004 and 2010 and due to its
lifetime of over 25 years would not require to be replaced.
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1.11
Com pliance with Laws, Statutes and Other Regulatory Fram eworks
The principal regulatory institutions of the energy sector are
•
The Ministry of Mines and Energy: This is the leading institution in Colombia’s energy sector.
•
The Unit for Mining and Energy Planning (UPME): This unit of the Ministry of Mines and
Energy is responsible for the study of future energy requirements and supply situations, as well
as for drawing up the National Energy Plan and Expansion Plan.
•
The Regulatory Commission for Gas and Energy (CREG): This entity is in charge of regulating
the market for the efficient supply of energy. It defines tariff structures for consumers,
transmission charges, and standards for the wholesale market, guaranteeing the quality and
reliability of the service and economic efficiency. It also provides regulations that ensure the rights
of consumers, the inclusion of environmental and socially sustainable principles, improved
coverage and financial sustainability for participating entities.
•
XM Compañía de Expertos en Mercados S.A. E.S.P.: This is a non-governmental agency
acting as the market administrator of the power sector, being in charge of the registration of
contracts, the settlement and billing of all the transactions that take place in this market. XM is
also in charge of the National Dispatch Center.
Table 2. Institutional structure of Colombian’s electricity market
Policies
Ministry of Mines & Energy
¡Error! Marcador no definido.
Planning
Planning Unit of the Mines and Energy (UPME)
Regulation
Commission for the Regulation of Energy and Gas (CREG)
.
The cogeneration project does not require any specific licenses. As per articles 8 and 9 of the Decree
2820 of 2010, it does not need to develop an Environmental Impact Assessment nor an environmental
license. Since it is within the limits of the manufacturing company, it complies with the rules established
for the manufacturer and may be operated under the current operating permission of the plant. Due to the
modification of the generation process, an Environmental Management Plan will be developed.
Energy purchase from the grid and sales of excess electric energy are ruled by the framework of the
1
Colombian energy market based on Laws 142 (Public Services Law) and 143 (Electricity Law) of 1994 ,
which represent the last major reform of the power sector and establish the current regulatory framework.
Since their enactment, Colombia has had a liberalized energy market, which is characterized by an
unbundled generation, transmission, distribution, and commercialization scheme in order to separate the
power activities and the markets. An electricity spot market and the development of a long-term contract
market for electricity sales are the core of new structure to introduce a more effective framework for
competition and an independent regulatory system supervised by the CREG (Regulatory Commission for
Energy and Gas), created by the Law 143. This Electricity Law specifically introduced rules regarding: (i)
Power sector planning; (ii) power generation; (iii) transmission and distribution; (iv) grid operation; (v) grid
1
Laws can be accessed on the website: http://www.creg.gov.co/cxc/secciones/documentos/leyes.htm
(accessed: 02/07/2014)
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access fees; (vi) regime for electricity sales; (vii) concessions and contracts; and (viii) environmental
issues, among others.
Clients
Distributor costs passed through to clients
Distribution + Power Retail
-Buying and selling of electricity
-Competition + Entry (Gradual)
Transmission
Operative Stage
Grid-free access
Regulated fees
ELECTRICITY
SPOT MARKET
Regulated users
Non-regulated users (<0.5
MW)
National Dispatch Center
Operation + Administration
Generation
Entry + Competition
Free prices
Figure 1: Simplified Scheme of the Colombian Power Market based on
Electricity Law from 1994 (Law 143).
The project complies with all applicable laws and regulatory requirements under this framework.
1.12
Ownership and Other Program s
1.12.1 Right of Use
The proof of title is given by the contract between Unibol S.A. and AXIA Energía S.A.S. that defines the
right to implement and operate the project within the manufacturing plant.
1.12.2 Emissions Trading Programs and Other Binding Limits
Not applicable.
1.12.3 Other Forms of Environmental Credit
The project has not been registered and is not seeking registration under any other GHG programs.
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1.12.4 Participation under Other GHG Programs
The project has no intends to generate any other form of GHG-related environmental credit for GHG
emission reductions or removals claimed under the VCS Program.
1.12.5 Projects Rejected by Other GHG Programs
The project has not has been rejected by any other GHG programs.
1.13
Additional Inform ation Relevant to the Project
Eligibility Criteria
The guidelines of the form to complete the Project Document stated that “For grouped projects, identify
eligibility criteria for inclusion of new instances of each project activity.” Since this is not a grouped
project, this is not applicable to the project activity.
Leakage Management
Not applicable as per the applied methodology.
Commercially Sensitive Information
No information has been excluded.
Further Information
Not applicable.
2
2.1
APPLICATION OF M ETHODOLOGY
Title and Reference of M ethodology
The project activity is developed in accordance with the approved small-scale CDM baseline and
monitoring methodology AMS-II.D. “Energy efficiency and fuel switching measures for industrial facilities”
(version 13.0.0).
(available at: http://cdm.unfccc.int/methodologies/SSCmethodologies/approved , accessed: 20/11/2014)
The identification of the baseline scenario and the demonstration of additionality are assessed by
applying the latest versions of the CDM “Tool for the demonstration and assessment of additionality”
(version 7.0.0).
(available at: http://cdm.unfccc.int/Reference/tools/index.html, accessed: 20/11/2014)
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The emission factor of the relevant power-grid is determined based on the procedures of the CDM “Tool
to calculate the emission factor for an electricity system” (version 4.0.0).
The project emissions from fuel consumption are determined based on “Tool to calculate project or
leakage CO2 emissions from fossil fuel combustion” (version 2.0.0).
Moreover, the following guidelines are applied:
“Guidelines on the assessment of investment analysis” (version 5) as per the Annex 5 of CDM EB 62
report.
(available at: http://cdm.unfccc.int/Reference/Guidclarif/index.html#pdd , accessed: 20/11/2014)
“Guidelines on common practice” (version 02.0) as per the Annex 8 of CDM EB 69 report.
(available at: http://cdm.unfccc.int/Reference/Guidclarif/index.html#pdd , accessed: 20/11/2014)
2.2
Applicability of M ethodology
The approved CDM small-scale methodology AMS-II.D. “Energy efficiency and fuel switching measures
for industrial facilities” (version 13.0.0) is applicable to any energy efficiency improvement measures
implemented at a single or several industrial or mining and mineral production facilities. The project
activities may involve:
•
Process energy efficiency improvement(s) affecting either a single production step/element
2
process (e.g. furnace, kiln) or a series of production steps/element processes (e.g. industrial
process involving many machines) that transform(s) raw materials (e.g. feed-stocks) and other
inputs into either intermediate forms or final finished outputs (e.g. molten metal, tiles, steel
ingots);
•
Energy efficiency improvement in energy conversion equipment (e.g. boiler, motor) that supplies
energy (thermal/electrical/mechanical) within a facility.
This project activity consists of the implementation of a new cogeneration plant with new high efficient
power generators and steam recovery boilers to provide electric and thermal energy to a manufacturing
process; hence if falls under “energy efficiency improvement in energy conversion equipment that
supplies energy (thermal/electrical/mechanical) within a facility.”
Additional applicability criteria of the methodology are:
•
2
This category is applicable to project activities where it is possible to directly measure and record
the energy use of the project activity within the project boundary (e.g. electricity and/or fossil fuel
An element process is a process, with associated equipment, in which an energy source (e.g. fuel, electricity,
steam) is used for production purposes to convert raw materials into intermediate or finished product using thermal
energy.
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consumption and/or the energy contained in the energy carrying medium (ECM) such as steam,
hot water, compressed air, etc.) and the quantities of such ECMs utilized in the project boundary.
The ‘direct measurement’ in the case of thermal energies (fossil fuel, steam/heat consumption)
does not have to involve the metering of energy itself but corresponding parameters such as
quantity of fossil fuel consumed, temperature/pressure and quantity amount of steam. The energy
flow then can be determined using acceptable engineering methods outlined in recognized
national or international standards in an accurate or conservative manner for example ASME
PTC 4-19983 or BS8454 can be used to determine thermal energy output of a baseline boiler
from actual measured baseline data for steam flow, pressure and temperature.
In this case, the consumption of natural gas for power and steam generation can be directly
measured.
•
This category is applicable to project activities where the impact of the measures implemented
(improvements in energy efficiency) by the project activity can be clearly accounted for and
documented as well as distinguished from changes in energy use due to other independent
variables not influenced by the project activity (signal to noise ratio). Examples of other variables
include upstream/downstream process factors, feedstock and product characteristics, and
environmental parameters (e.g. ambient temperature, humidity) associated with the baseline or
project activity that may influence the energy savings from the project activity.
Since the project is a cogeneration plant that delivers electric and thermal energy to a
manufacturing plant, it can be clearly separated from the production processes. The project
activity does not influence energy requirements of the process, i.e. the baseline power and steam
consumption would be identical.
Since the project meets all conditions, the methodology is applicable to the proposed project activity.
2.3
Project Boundary
The project boundary is the physical, geographical site of the energy generation facility, including all
processes and equipment that are affected by the project activity. The energy inputs to and outputs from
the project boundary are transparently defined in this PDD. The following figures show simplified
schemes of the energy inputs and outputs in the baseline scenario (situation prior to project
implementation) and in the project scenario (with the new cogeneration plant).
3
American Society of Mechanical Engineers Performance Test Codes for Steam Generators: ASMEPTC 4 – 1998;
Fired Steam Generators.
4
British Standard Methods for Assessing the Thermal Performance of Boilers for Steam, Hot Water and High
Temperature Heat Transfer Fluids.
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Project boundary
Coal
Steam boiler
20,700 lbs/hr
Natural gas
Steam boiler
20,700 lbs/hr
Heat recovery boiler 1
1,500 lbs/hr
Process steam
1)  Electric energy
consumption
2)  Thermal energy
consumption
(steam)
Heat recovery boiler 2
1,500 lbs/hr
Power generator 1
Cummins 1.75 MW
Natural
gas
Paper manufacturing
process of Unibol S.A.
Power
Power generator 2
Cummins 1.75 MW
Power from the grid
Measuring point (production)
Measuring point (consumption)
Figure 2: Project boundary and measurement points in the BASELINE.
Project boundary
Natural gas
Steam boiler
20,700 lbs/hr
Paper manufacturing
Excess
heat
Natural
gas
Heat recovery boiler
6,000 lbs/hr
Power generator
Hyundai 14H35/40GV
6.7 MW
Process steam
consumption
consumption
(steam)
Power
Figure 3: Project boundary and measurement point with the PROJECT ACTIVITY.
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The spatial extent of the project boundary is the National Interconnected System (SIN5) of Colombia. The
power plants of this grid are all connected and can be dispatched without significant transmission
constraints.
Baseline
Source
CO2 emissions from fossil fuel
consumption in the baseline
equipment (i.e. 2 x Cummins
power generators, 1 x steam
boiler)
Project
CO2 emissions from electricity
consumption from the grid
2.4
CO2 emissions from fossil fuel
consumption in the project
equipment (i.e. 1 x Hyundai
power generator, 1 x steam
boiler)
Gas
Included?
Justification/Explanation
CO2
Yes
Main emission source
CH4
No
Minor emission source
N 2O
No
Other
No
No other emission sources
CO2
Yes
CH4
No
N 2O
No
Other
No
CO2
Yes
CH4
No
N 2O
No
Other
No
Baseline Scenario
The baseline scenario is the same scenario as prior to project implementation. The existing generators
and recovery boilers are relatively new, installed between the years 2004 and 2010. Due to the lifetime of
over 25 years of such equipment, the current systems for electric and thermal energy generation could
continue operation over more than 10 years, thus it corresponds to the baseline equipment:
ü
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5
28%
in Spanish: Sistema Interconectado Nacional
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2.5
Additionality
In this section, the additionality of the project activity is analyzed.
In the following timeline, the past events are summarized and completed with expected future actions:
Table 3. Overview of key events in the development of the proposed project
Date
Key event
October 2013 –
June 2014
June 2014
October 2014
October 2014
October 2014 –
January 2015
February 2015 –
July 2015
July 2015
Basic studies of alternatives for electric and thermal energy generation at Unibol
Technical and economical proposal
Investment decision on 15 October 2014
Signature of contract between AXIA Energia S.A.S. and Fábrica de Bolsas de
Papel Unibol S.A.
Detailed project design of auxiliary equipment and control
Project implementation
Operational start
The additionality of the project activity is demonstrated and assessed applying the CDM “Tool for the
demonstration and assessment of additionality” (version 7.0.0), as stated in the methodology ACM0002
(version 15.0.0) and accepted by the VCS Standard 3 (version 3.4).
The tool provides a step-wise approach to demonstrate and assess additionality:
Step 0.
Demonstration whether the proposed project activity is the first-of-its-kind;
Step 1.
Identification of alternatives to the project activity;
Step 2.
Investment analysis to determine that the proposed project activity is either: (1) not the
most economically or financially attractive, or (2) not economically or financially feasible;
Step 3.
Barriers analysis; and
Step 4.
Common practice analysis.
Step 0: Demonstration whether the proposed project activity is the first-of-its-kind
This step is optional. It is not applied for this project activity and therefore it is considered that the
proposed project activity is not the first-of-its-kind.
Step 1: Identification of alternatives to the project activity consistent with current laws and
regulations
Realistic and credible alternatives to the project activity(s) are defined through the following substeps:
Sub-step 1a: Define alternatives to the project activity
The possible alternatives to the proposed project include:
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Alternative 1: The proposed project activity undertaken without being registered as a CDM project
activity.
Alternative 2: Continuation of the current situation: In this case, the project activity will not be constructed
and the power and steam will be generated as in the situation prior to project implementation..
Sub-step 1b: Consistency with mandatory laws and regulations
Both alternatives identified in sup-step 1a are in compliance with mandatory laws and regulations as per
section 1.11:
Alternative 1: The proposed project activity undertaken without being registered as a CDM project
activity.
Alternative 2: Continuation of the current situation: In this case, the project activity will not be constructed
and the power will be solely supplied by the operation of power plants connected to the SIN and by the
addition of new power plants.
Step 2: Investment analysis
To conduct the investment analysis, following Sub-steps are used:
Sub-step 2a: Determine appropriate analysis method
According to CDM “Tool for the demonstration and assessment of additionality” (version 7.0.0), three
options can be applied for the investment analysis: the simple cost analysis, the investment comparison
analysis and the benchmark analysis.
The project activity generates financial and economic benefits other than CER revenues, therefore the
simple cost analysis (Option I) is not applicable. Since the only investment option for the project
proponent is Alternative 2, Option II (investment comparison analysis) is also not applicable and the
benchmark analysis (Option III) is chosen to prove additionality.
Sub-step 2b – Option III: Apply benchmark analysis
The additionality tool requires an identification of the most appropriate financial indicator. For the case of
a cogeneration plant that provides electric and thermal energy to an end-user, the most appropriate
indicator is the internal rate of return (IRR) as it characterizes the rate of return on invested capital. In this
analysis an equity IRR is calculated in accordance with the additionality tool and the corresponding
guidelines as indicated above. Taxation is included as an expense in the IRR calculation, i.e. the IRR is
determined as a post-tax indicator.
In accordance with the “Guidelines on the assessment of investment analysis” (version 5) a default value
for the expected return on equity is used for the benchmark. The relevant benchmark for energy projects
in Colombia (Group 1 as given in the guidelines) is 12.0% in real terms. As per the guidelines, since the
investment analysis is carried out in nominal terms, the real term values provided can be converted to
nominal values by adding the inflation rate. Since no long-term inflation forecasts or target rates of the
central bank for the duration of the crediting period exist, the average forecasted inflation rate of 3.0% five
v3.2
16
years available by the IMF (International Monetary Fund World Economic Outlook) is used (based on the
6
forecasts for the period from 2015 to 2019, which represent the most recent data available).
The benchmark, i.e. the Nominal Return on Equity, is therefore given as 15.0%.
Sub-step 2c: Calculation and comparison of financial indicators
For the financial analysis the main cash outflows are given by the investment, the ongoing O&M costs
and taxes. The cash inflows are mainly generated from revenues of energy sales. In this case, the price is
defined by the amount of electric energy delivered, will the steam from the recovery boiler is covered by
the same tariff.
Input values for the investment analysis
The financial structure is applied as suggested by the guidelines for investment analysis (version 5). For
the equity/debt structure, the default ratio of 50% equity and 50% debt is used. Typical terms of the debt
observed in the power sector are used. The lending rate is taken from public data. A summary of the debt
used for the investment analysis is given in the following table.
7
Table 4: Terms of debt structure .
Source
Value
Parameter
Total investment (USD)
$6,652,500
% Debt
50%
Equity amount (USD)
$3,326,250
Loan amount (USD)
$3,326,250
Interest rate (p.a.)
11.00%
Principal (annual)
$332,625
Total investment amount
Based on the default value of the Guidelines for Investment
Analysis
Calculated (50%)
Calculated (50%)
The average of the most recent five years prior to decisionmaking is taken (World, Bank, 2009-2013). The following link
provides the rates
http://data.worldbank.org/indicator/FR.INR.LEND
Annual principal during 10 years
Table 5 lists the parameters and values used for carrying out the investment analysis. The inputs are the
values available at the moment of decision making. The energy generation is based on the historical
consumption of the paper manufacturing plant during the most recent 12 months with an annual expected
growth of 4%. The energy tariff is established in the contract and depends on the monthly generation
amount. All sources and further details are provided in the Investment Analysis spreadsheets.
An assessment period of 10 years is applied, with a construction period of 6 months.
Table 5. Input values used in the investment analysis available at the moment of decision making
8
(all sources and calculations are provided in the Investment Analysis spreadsheets ).
Electricity generation
6
International Monetary Fund, World Economic Outlook (IMF) Database, (accessed: 20/11/2014)
http://www.imf.org/external/pubs/ft/weo/2014/01/weodata/weorept.aspx?sy=2012&ey=2019&scsm=1&ssd=1&sort=co
untry&ds=.&br=1&pr1.x=74&pr1.y=12&c=233&s=PCPIPCH&grp=0&a=
7
For details and specific sources, see spreadsheet “Debt” of the Investment Analysis in the Excel file “Equity IRR
AXIA Energia Cogeneration Project in Unibol”
8
see “Equity IRR AXIA Energia Cogeneration Project in Unibol”
v3.2
17
Capacity
Net energy generation
6.518
3,641
kW
GWh / year
173.80
COP/kWh
Tariffs
Electricity sales
Energy tariff (average 2015 - 2025)
INVESTMENT
Total Capital Costs
Total Investment
$6,652,500
USD
$2,425,062
USD/year
OPERATING COSTS & EXPENSES
Operation costs
O&M costs
Taxes
Income taxes
33.0%
%
Depreciation
Depreciation period
10
years
FINANCIAL PARAMETERS
Macro
Exchange rate
Producer Price Index
Discount rate
1,827
1.29%
11.0%
COP/USD
%
%
12.0%
3.0%
15.0%
%
%
%
Benchmark
Return on Equity (real terms)
Inflation Adjustment
BENCHMARK: Nominal Return on Equity
Result of the investment analysis
Based on the parameters above, the Internal Rate of Return (post-tax equity IRR) is calculated as 6.0%,
which is below the benchmark rate of 15.0%.
Sub-step 2d: Sensitivity analysis
A sensitivity analysis is carried out by varying the following key parameters to analyze the impact on the
equity IRR:
•
•
•
Energy generation (MWh): The quantity of energy generated is varied.
Investment costs (USD): the complete investment cost is varied.
O&M costs (USD/year): the complete operational cost is varied (including O&M, administration,
sales costs and socioeconomic costs)
The energy tariff is not varied since it will be fixed under the energy sales agreement.
Table 6 shows a sensitive analysis for the resulting IRR by varying the main parameters +/- 10%.
Table 6: Sensitivity analysis.
Variation of electricity generation
Base
IRR
6.0%
v3.2
+10.0%
9.9%
18
Variation of investment costs
IRR
Base
6.0%
-10.0%
10.3%
Variation of O&M costs
IRR
Base
6.0%
-10.0%
12.6%
As can be seen, the benchmark is not reached in these scenarios; thus it can be concluded that the
project activity is not financially attractive.
Step 3: Barrier analysis
The project activity does not apply a barrier analysis.
Step 4: Common practice analysis
The above additionality test is complemented with an analysis of the extent to which the proposed project
type (i.e. the technology) has already diffused in the industrial sector in the project region. The applicable
geographical area for the assessment of common practice analysis corresponds to the host country
Colombia. This test is a credibility check to complement the investment analysis (Step 2).
Since the specific information of individual industrial plants with similar characteristics and their electric
and thermal energy generation systems is not available, a general analysis is conducted to assess to
which extent similar activities to the proposed CDM project activity have been implemented in Colombia.
In this case, similar activities are cogeneration systems in similar industrial manufacturing plants that are
of similar scale, take place in a comparable environment and are undertaken in the applicable
geographical area, as defined above. The criteria of similar activities can be summarized as:
•
•
•
•
Technology: Cogeneration systems based on natural gas
Industrial sector: paper
Geographical region: Colombia
Installed power generation capacity: 5-10 MW
The most complete study about the diffusion of cogeneration plants in Colombia has been published by
9
the National Association of Businesses (ANDI ) in its “Inventory of the installed capacity of autogeneration
10
and cogeneration in the Colombian industry” .
The study in total identifies 21 cogeneration plants in Colombia. The main energy source for is biomass,
which basically are the sugar refineries that have a lot of biomass wastes at no cost and constitutes a
total installed capacity of 205.3 MW. Considering that only 16% of the cogeneration systems
(corresponding to 58 MW) use natural gas and that those are distributed between different sectors (e.g.
paper, textiles, others), it can be concluded that the number of such cogeneration facilities in the project
capacity´s range is still relatively small and the project is not a common practice.
9
in Spanish: Asociación Nacional de Empresarios de Colombia
10
“Inventario de la Capacidad Instalada de Autogeneración y Cogeneración en la Industria Colombiana”, see
“201408-Inventario de Auto y Cogeneracion.pdf”
v3.2
19
Conclusion of the additionality analysis
Since the project activity is not financially attractive (step 2) and the common practice analysis shows that
it is not business-as-usual (Step 4), the proposed project activity is additional.
2.6
M ethodology Deviations
Not applicable. No methodology deviations are made.
3
QUANTIFICATION OF GHG EM ISSION REDUCTIONS AND REM OVALS
3.1
Baseline Em issions
As per the methodology AMS-II.D. (version 13.0), paragraph 23, the baseline consists of the energy
consumption that would have occurred in the absence of the project activity for the existing facility that is
replaced. As explained section 2.4, this baseline scenario is the same scenario as prior to project
implementation, including the following equipment:
ü
ü
ü
ü
ü
28%
The baseline determination is based on the relevant operational data for the existing equipment, since the
continuation of current practice is the baseline scenario.
11
The baseline emissions are estimated as follows (only the relevant terms are included ):
𝐵𝐸! = !
!!! 𝐸𝐶! × 𝐸𝐹!,!
+
!
!!!
!
!!! 𝐹𝐶!,! × 𝑁𝐶𝑉! ×𝐸𝐹!!,!
(1)
Where:
11
The term including ECM (flow rate of steam) is not relevant, since the fossil fuel energy consumption to produce
the steam is taken into account to estimate baseline emissions in the term with FC (fuel consumption). See comment
under the parameter “𝐸𝐶𝑀! ” on page 10 of the methodology. Besides, the term with Qref,BL is also zero, since no
refrigerants are used in the project.
v3.2
20
𝐵𝐸!
=
Baseline emissions during year y of the project activity (t CO2e/year)
𝐸𝐶!
=
The amount of electricity consumption by baseline device i or processl(MWh)
𝐸𝐹!,!
=
Emission factor of the electricity consumption by process i (t CO2e/MWh).
Electricity emission factor of grid is calculated in accordance with the “Tool to
calculate the emission factor for an electricity system” represented by the cobined
margin emission factor EFgrid,CM,y.
𝑖
=
Process i which consume electricity in baseline scenario
𝑛
=
Number of device or processes which consumes electricity in baseline scenario
𝐹𝐶!,!
=
The volume of the baseline fossil fuel type k consumed by baseline device j (Nm3
or tonnes)
𝑁𝐶𝑉!
=
The net calorific value of the baseline fossil fuel type k (TJ/Nm3 or TJ/tonnes)
𝐸𝐹!!,!
=
Emission factor of the baseline fossil fuel type k (t CO2e/TJ)
𝑗
=
Device j which consumes fossil fuel in baseline
𝑘
=
Baseline fossil fuel type k
𝑚
=
Number of device which consumes fossil fuel in baseline
𝑝
=
Number of types of the fossil fuel
The following are the relevant indexes as per the baseline equipment and energy consumption pattern:
Index
i
Values
grid
n
1
j
G1
G2
GB
CB
k
NG
Coal
Comments
There is no electricity imports from captive power plants in the
baseline. The only electricity imports are from the grid. The grid
emission factor is calculated based on the “Tool to calculate the
emission factor for an electricity system” as outlined below.
As explained above, there is only one external power source, which in
this case is the power grid.
In the baseline there are four devices consuming fossil fuel, which are
the Generator 1 (G1) with 1.75 MW, the Generator 2 (G2) with 1.75
MW, the natural gas boiler (GB) with a steam generation capacity of
20.700 lbs/hr and the coal-fired boiler (GB) with a steam generation
capacity of 20.700 lbs/hr.
The baseline fossil fuel is natural gas for j=G1,G2,GB
and coal for j=CB
Electricity emission factor of grid
The electricity emission factor of grid is given by the combined margin emission factor based on the tool
12
“Tool to calculate the emission factor for an electricity system” .
Baseline emissions include only CO2 emissions from electricity generation in fossil fuel fired power plants
that are connected to the grid. The combined margin emission factor of the SIN has been adopted by the
13
Ministry of Energy and Mines of Colombia and calculated by the UPME as 0.374 tCO2/MWh.
12
Available at: https://cdm.unfccc.int/methodologies/PAmethodologies/approved (accessed: 29/12/2014)
v3.2
21
In the following, the general methodological approaches and formulas applied by the UPME based on the
14
“Tool to calculate the emission factor for an electricity system” (version 4.0.0) are explained.
The combined margin emission factor (EFE,i = EFgrid,CM,y) is calculated following the guidance in the “Tool
to calculate the emission factor for an electricity system” (version 4.0.0) by applying the following steps:
STEP 1.
STEP 2.
STEP 3.
STEP 4.
STEP 5.
STEP 6.
Identify the relevant electricity systems;
Choose whether to include off-grid power plants in the project electricity system (optional);
Select a method to determine the operating margin (OM);
Calculate the operating margin emission factor according to the selected method;
Calculate the build margin (BM) emission factor;
Calculate the combined margin (CM) emissions factor.
In the following it is explained how each step is applied by the Ministry for .
STEP 1. Identify the relevant electricity systems.
For determining the electricity emission factors, the project electricity system is defined by the spatial
extent of the power plants that are physically connected through transmission and distribution lines to the
project activity (i.e., AXIA Energia Cogeneration Project in Unibol) and that can be dispatched without
significant transmission constraints. In this case, the project electricity system is given as the National
Interconnected System (SIN).
STEP 2. Choose whether to include off-grid power plants in the project electricity system (optional).
In accordance with the tool, this step is optional. The UPME calculations do not include off-grid power
plants.
STEP 3. Select a method to determine the operating margin (OM).
In accordance with the tool, the calculation of the operating margin emission factor (EFgrid,OM,y) is based
on one of the following methods:
(a) Simple OM; or
(b) Simple adjusted OM; or
(c) Dispatch data analysis OM; or
(d) Average OM.
As explained in the UPME document, the simple adjusted OM is the most reasonable method and used
for this calculations. All power plants connected to the SIN are included.
STEP 4. Calculate the operating margin emission factor according to the selected method.
The simple adjusted operating margin emission factor EFgrid,OM-adj,y (tCO2e/MWh) is a variation of the
simple operating margin emission factor , where the power sources (including imports) are separated in
low-cost/must-run power sources (k) and other power sources (j), as follows:
13
see Resolution 9 1304 from 25/11/2014, available at: http://www.minminas.gov.co/documents/10180/23517/26203Resolucion-91304-25nov2014.pdf (accessed: 02/12/2014)
14
see “FACTORES DE EMISION DEL S.I.N. SISTEMA INTERCONECTADO NACIONAL COLOMBIA 2013”,
http://www.siame.gov.co/siame/documentos/Calculo_FE_SIN_2013_Nov2014.pdf (accessed: 02/12/2014)
v3.2
22
∑EG ⋅ EF
∑EG
m,y
EFgrid,OM−adj,y = (1− λ y ) ⋅
∑EG
k,y
EL,m,y
m
+ λy ⋅
m,y
m
Where:
λy
EGm,y
EGk,y
EFEL,m,y
EFEL,k,y
m
k
⋅ EFEL,k,y
i,j
∑EG
(2)
k,y
k
= Factor expressing the percentage of time when low-cost/must-run power units are on
the margin in year y
= Net quantity of electricity generated and delivered to the grid by power unit m in year
y (MWh)
= Net quantity of electricity generated and delivered to the grid by power unit k in year y
(MWh)
= CO2 emission factor of power unit m in year y (tCO2/MWh)
= CO2 emission factor of power unit k in year y (tCO2/MWh)
= All grid power units serving the grid in year y except low-cost/must-run power units
= All low-cost/must run grid power units serving the grid in year y
The lambda factor (λ) is determined as:
λ=
number of hours per year low − cos t / must − run sources are on the margin
8760 hours per year
(3)
According to the methodology, the number of hours low-cost/must-run sources are on the margin is
obtained through the following procedure (see ¡Error! No se encuentra el origen de la referencia.
below):
Step i) Plot a Load Duration Curve
Collect chronological load data (typically in MW) for each hour of the year y, and sort the load data from
the highest to the lowest MW level. Plot MW against 8760 hours in the year in descending order.
Step ii) Organize Data by Generating Sources
Collect electricity generation data from each power plant/unit. Calculate the total annual generation (in
MWh) from low-cost/must-run power plants/units.
Step iii) Fill Load Duration Curve
Fill the load duration curve. Plot a horizontal line across the load duration curve such that the area under
horizontal line and the curve right from the intersection point (MW times hours) equals the total generation
(in MWh) from low-cost/must-run power plants/units
Step iv) Determine the “Number of hours per year low-cost/must-run sources are on the margin”
Determine the “Number of hours for which low-cost/must-run sources are on the margin in year y. First,
locate the intersection of the horizontal line plotted in Step (iii) and the load duration curve plotted in Step
(i). The number of hours (out of the total of 8760 hours) to the right of the intersection is the number of
hours for which low-cost/must-run sources are on the margin. If the lines do not intersect, then one may
conclude that low-cost/must-run sources do not appear on the margin and lambda is equal to zero.
STEP 5. Calculate the build margin (BM) emission factor
The sample group of power units m used to calculate the build margin is determined as per the following
procedure:
v3.2
23
(a) Identify the set of five power units, excluding power units registered as CDM project activities,
that started to supply electricity to the grid most recently (SET5-units) and determine their annual
electricity generation (AEGSET-5-units, in MWh);
(b) Determine the annual electricity generation of the project electricity system, excluding power units
registered as CDM project activities (AEGtotal, in MWh). Identify the set of power units, excluding
power units registered as CDM project activities, that started to supply electricity to the grid most
recently and that comprise 20% of AEGtotal (if 20% falls on part of the generation of a unit, the
generation of that unit is fully included in the calculation) (SET≥20%) and determine their annual
electricity generation (AEGSET-≥20%, in MWh);
(c) From SET5-units and SET≥20% select the set of power units that comprises the larger annual
electricity generation (SETsample);
Identify the date when the power units in SETsample started to supply electricity to the grid. If none
of the power units in SETsample started to supply electricity to the grid more than 10 years ago,
then use SETsample to calculate the build margin. Ignore steps (d), (e) and (f).
Otherwise:
(d) Exclude from SETsample the power units which started to supply electricity to the grid more than 10
years ago. Include in that set the power units registered as CDM project activity, starting with
power units that started to supply electricity to the grid most recently, until the electricity
generation of the new set comprises 20% of the annual electricity generation of the project
electricity system (if 20% falls on part of the generation of a unit, the generation of that unit is fully
included in the calculation) to the extent is possible. Determine for the resulting set (SETsample-CDM)
the annual electricity generation (AEGSET-sample-CDM, in MWh); If the annual electricity generation of
that set is comprises at least 20% of the annual electricity generation of the project electricity
system (i.e. AEGSET-sample-CDM ≥ 0.2 × EGtotal), then use the sample group SETsample-CDM to calculate
the build margin. Ignore steps (e) and (f).
Otherwise:
(e) Include in the sample group SETsample-CDM the power units that started to supply electricity to the
grid more than 10 years ago until the electricity generation of the new set comprises 20% of the
annual electricity generation of the project electricity system (if 20% falls on part of the generation
of a unit, the generation of that unit is fully included in the calculation);
(f) The sample group of power units m used to calculate the build margin is the resulting set
(SETsample-CDM->10yrs).
The build margin emissions factor is the generation-weighted average emission factor (tCO2/MWh) of all
power units m during the most recent year y for which power generation data is available, i.e. in this case
the year 2013. The calculation is made as follows:
∑EG × EF
∑EG
m,y
EFgrid,BM,y =
EL,m,y
m
(4)
m,y
m
Where:
EFgrid,BM,y
EGm,y
EFEL,m,y
v3.2
= Build margin CO2 emission factor in year y (tCO2/MWh)
= Net quantity of electricity generated and delivered to the grid by power unit m in year y
(MWh)
= CO2 emission factor of power unit m in year y (tCO2/MWh)
24
m
y
= Power units included in the build margin
= Most recent historical year for which power generation data is available
Step 6: Calculate the combined margin (CM) emissions factor
The combined margin emissions factor is calculated as follows:
(5)
EFgrid,CM,y = EFgrid,OM,y × w OM + EFgrid,BM,y × wBM
Where:
EFgrid,OM,y
EFgrid,BM,y
wOM
wBM
=
=
=
=
Operating margin CO2 emission factor in year y (tCO2/MWh)
Build margin CO2 emission factor in year y (tCO2/MWh)
Weighting of operating margin emissions factor (%)
Weighting of build margin emissions factor (%)
The weighting of operating and build margin is done as indicated in the tool for the first crediting period,
i.e. wOM = 0.5 and wBM = 0.5.
Table 7 shows the summary of the UPME calculations of the CM.
Table 7: Combined margin emission factor of the year 2013.
2013
EF operating margin (tCO2/MWh) 0.630
62,196,587
Total generation (MWh)
0.1172
EF build margin (tCO2/MWh)
0.5
wOM
0.5
wBM
EFgrid,CM,2013 (tCO2/MWh)
0.374
The individual terms of the annual baseline emissions of equation (1) are:
COMPONENT
FORMULAE AND VALUES
RESULT
Grid electricity
consumption
𝐸𝐶!"#$ × 𝐸𝐹!,!"#$ = 8,923 MWh x 0.374 tCO2/MWh 3,337 tCO2
Natural gas
consumption in
generator 1 (G1)
𝐹𝐶!!,!" ×𝑁𝐶𝑉!" ×𝐸𝐹!!,!" = 3,281,741 m3 x
7,125 tCO2
Natural gas
consumption in
generator 2 (G2)
𝐹𝐶!!,!" ×𝑁𝐶𝑉!" ×𝐸𝐹!!,!" = 3,338,087 m3 x
7,247 tCO2
𝐹𝐶!",!" ×𝑁𝐶𝑉!" ×𝐸𝐹!!,!" = 2,272,864 m3 x
4,935 tCO2
𝐹𝐶!",!"#$ ×𝑁𝐶𝑉!"#$ ×𝐸𝐹!!,!"#$ = 2,156 tons x
5,689 tCO2
Natural gas
consumption in
natural gas steam
boiler (GB)
Natural gas
consumption in
coal-fired steam
boiler (CB)
v3.2
3
0.0000374 TJ/m x 56.1 tCO2/MWh
3
0.0000374 TJ/m x 56.1 tCO2/MWh
3
0.0000374 TJ/m x 56.1 tCO2/MWh
0.0293 TJ/ton x 94 tCO2/MWh
25
TOTAL BASELINE EMISSIONS
3.2
28,333 tCO2
Project Em issions
As per the applied methodology, paragraph 47, the project emissions are equal to:
15
(a) The emissions associated with consumption of fossil fuel, electricity and ECM within the project
boundary by the project systems;
(b) The emissions associated with any refrigerants used in new project cooling equipment (e.g.
electrical compression chillers.
As in the baseline emissions, the terms related to ECM and refrigerants are not relevant. Besides, the
electric energy is completely generated with the plant and no consumption from the grid is expected.
There may be some grid consumption during maintenance, however it is considered that this effect is not
relevant. Thus, the project emissions are given by the emissions from fossil fuel consumption as follows:
(6)
𝑃𝐸! = 𝑃𝐸!!,!
Where:
𝑃𝐸!
=
Project emissions in year y (t CO2e)
𝑃𝐸!!,!
=
Project emissions due to fossil fuel and shall be estimated following the
latest version of “Tool to calculate project or leakage CO2 emissions from
fossil fuel consumption”
Based on the “Tool to calculate project or leakage CO2 emissions from fossil fuel consumption”, the
following equation is applied for the project emissions due to fossil fuel:
𝑃𝐸!!,! = 𝑃𝐸!",!,! =
𝐹𝐶!,!,! × 𝐶𝑂𝐸𝐹!,! (7)
!
Where:
𝑃𝐸!",!,!
=
CO2 emissions from fossil fuel combustion in process j during the year y
(tCO2/yr)
𝐹𝐶!,!,!
=
Quantity of fuel type i combusted in process j during the year y (mass or
volume unit/yr);
𝐶𝑂𝐸𝐹!,!
=
CO2 emission coefficient of fuel type i in year y (tCO2/mass or volume
unit)
i
=
Fuel types combusted in process j during the year y
The following are the relevant indexes as per the project equipment and energy consumption pattern:
Index
j
15
Values
HG
GB
Comments
In the project scenario there are two equipment consuming natural
gas, including the new Hyundai Generator (HG) with 6.7 MW and the
Flow rate of steam
v3.2
26
i
Natural Gas Boiler (GB) with a steam generation capacity of 20.000
lbs/hr.
The fuel consumption in the project activity consists of natural gas
(NG) only.
NG
The individual terms of the annual project emissions of equation (7) are:
COMPONENT
FORMULAE AND VALUES
RESULT
Natural gas
consumption in
generator 1 (G1)
𝐹𝐶 !",!" × 𝐶𝑂𝐸𝐹!"
= 6,637,768 m3 x 0.002096 tCO2/m3 13,931 tCO2
Natural gas
consumption in
natural gas steam
boiler (GB)
𝐹𝐶 !",!" × 𝐶𝑂𝐸𝐹!"
= 2,121,703 m3 x 0.002096 tCO2/m3 4,603 tCO2
TOTAL PROJECT EMISSIONS
3.3
18,516 tCO2
Leakage
As per the methodology, if the energy efficiency technology is equipment transferred from another
activity, leakage is to be considered. Since the project activity uses new the equipment that is not
transferred from another activity, leakage is zero:
LEy = 0
3.4
Net GHG Em ission Reductions and Rem ovals
Since project emissions and leakage emissions are zero, emission reductions are directly given as the
baseline emissions as follows:
(8)
ER y = BEy − PEy − LEy = BEy
Where:
ERy
BEy
PEy
PEy
=
=
=
=
Emission reductions in year y (tCO2e/yr)
Baseline emissions in year y (tCO2/yr)
Project emissions in year y (tCO2e/yr)
Project emissions in year y (tCO2e/yr)
Thus: ERy = 100,534 tCO2/yr
Year
2015
2016
v3.2
(1)
Estimated
baseline
emissions or
removals (tCO2e)
Estimated project
emissions or
removals (tCO2e)
Estimated
leakage
emissions
(tCO2e)
Estimated net
GHG emission
reductions or
removals (tCO2e)
4,908
0
0
4,908
9,817
0
0
9,817
27
2017
9,817
0
0
9,817
2018
9,817
0
0
9,817
2019
9,817
0
0
9,817
2020
9,817
0
0
9,817
2021
9,817
0
0
9,817
2022
9,817
0
0
9,817
2023
9,817
0
0
9,817
9,817
0
0
9,817
4,908
0
0
4,908
98,170
0
0
98,170
2024
2025
(2)
Total
(1) 01/09/2015 – 31/12/2015
(2) 01/01/2025 – 31/08/2025
4
4.1
M ONITORING
Data and Param eters Available at Validation
Data / Parameter
ECgrid
Data unit
MWh
Description
Amount of electricity consumption in the baseline
Source of data
Historical data of the most recent 12 months
Value applied:
8,923 MWh
Justification of choice of
data or description of
measurement methods
and procedures applied
As per the methodology
Purpose of Data
Baseline emissions
Comments
v3.2
Data / Parameter
EFE,i
Data unit
tCO2/MWh
Description
Emission factor of the grid electricity that is given by the combined
margin emission factor based on the “Tool to calculate the
emission factor for an electricity system”.
Source of data
The combined margin emission factor of the SIN has been
adopted by the Environmental Ministry of Colombia and calculated
by the UPME as 0.374 tCO2/MWh.
28
See Resolution 9 1304 from 25/11/2014
16
and
“FACTORES DE EMISION DEL S.I.N. SISTEMA
17
INTERCONECTADO NACIONAL COLOMBIA 2013”
Value applied:
0.374 tCO2/MWh
measurement methods
Public value published by the Environmental Ministry of Colombia
Purpose of Data
Baseline emissions
Comments
Data / Parameter
FCj,k
Data unit
Nm3 or tonnes
Description
The volume of the baseline fossil fuel type k consumed by
baseline device j
Source of data
Value applied:
The following fossil fuel consumption takes place in the baseline:
Equipment
Fuel type
Amount
Generator 1 (G1)
Natural gas
3,281,741 m
3
Generator 2 (G2)
Natural gas
3,338,087 m
3
Natural Gas Boiler (NB)
Natural gas
2,272,864 m
3
Coal Boiler (CB)
Coal
2,156 tons
measurement methods
Purpose of Data
Baseline emissions
Comments
Data / Parameter
NCVk
Data unit
TJ/Nm3 or TJ/tonnes
Description
The net calorific value of the baseline fossil fuel type k
Source of data
16
http://www.minminas.gov.co/documents/10180/23517/26203-Resolucion-91304-25nov2014.pdf
(accessed: 02/12/2014)
17
http://www.siame.gov.co/siame/documentos/Calculo_FE_SIN_2013_Nov2014.pdf (accessed: 02/12/2014)
v3.2
29
Value applied:
Natural gas: 0.0000387 TJ/m
3
Coal: 0.0279 TJ/ton
measurement methods
http://www.natural-gas.com.au/about/references.html
Purpose of Data
Baseline emissions
Comments
Data / Parameter
EFFF,k
Data unit
tCO2/TJ
Description
Emission factor of the baseline fossil fuel type k
Source of data
IPCC Guidelines 2006, Chapter 2 “Stationary combustion”, Table
2.2 on page 2.17
Value applied:
Natural gas: 56.1 tCO2/TJ
Coal: 94.6 tCO2/TJ
measurement methods
Default emission factor for natural gas of the IPCC Guidelines
2006
Purpose of Data
Baseline emissions
Comments
4.2
Data and Param eters M onitored
Data / Parameter
FCi,j,y
Data unit
mass or volume unit
Description
Quantity of fuel type i combusted in process j during the year y
Source of data
Flow meters for Hyundai generator and steam boiler
Description of
measurement methods
and procedures to be
applied
Continuous measurement with flow meters
Frequency of
monitoring/recording
Continuous measurement and at least daily recording
Value applied:
Hyundai generador: 6,408,395 m /year
3
3
Natural gas boiler: 2,120,156 m /year
Monitoring equipment
v3.2
Flow meters and weight scales will be installed
30
QA/QC procedures to be
applied
Calibration tasks follow international standards
Purpose of data
Project emissions
Calculation method
All data collected as part of the monitoring process is archived
electronically and kept at least for two years after the end of the
last crediting period.
Comments
Data / Parameter
COEFi,y
Data unit
tCO2/mass or volume unit
Description
CO2 emission coefficient of fuel type i in year y
Source of data
Determined based on the NCV of 0.0000374 TJ/m and the IPCC
emission factor for natural gas of 56.1 tCO2/TJ
Description of
measurement methods
and procedures to be
applied
The emission factor will be determined based on the carbon
content of the natural gas from the provider’s specifications
Frequency of
monitoring/recording
Monthly
Value applied:
0.002171 tCO2/m3
Monitoring equipment
N/A
QA/QC procedures to be
applied
N/A
Purpose of data
Project emissions
Calculation method
All data collected as part of the monitoring process is archived
electronically and kept at least for two years after the end of the
last crediting period.
3
Comments
4.3
M onitoring Plan
The Monitoring Plan basically consists in the procedures to meter the following parameters:
•
•
•
v3.2
Natural gas consumption of the Hyundai generator and the steam boiler with two separate flow
meters
Steam production of the steam boiler and the heat recovery boiler
Power generation with the Hyundai generator
31
Project boundary
Natural gas
Steam boiler
20,700 lbs/hr
Paper manufacturing
Excess
heat
Natural
gas
Heat recovery boiler
6,000 lbs/hr
Power generator
Hyundai 14H35/40GV
6.7 MW
Process steam
consumption
consumption
(steam)
Power
Figure 4: Simplified scheme of the monitoring.
QA/QC measures
The meters are calibrated every two years. Calibration tasks follow international standards and will be
established once the meters are selected and installed. A cross-check will be done with invoices from the
natural gas provider.
Personnel responsible for monitoring
Figure 5 shows the organizational chart of the monitoring.
VCS Coordinators
Calculation of emission reductions, development of monitoring Report, verifying
the data and consolidation of numbers, responsible of getting the information for
validation and verification, supervision of the monitoring process
Plant Manager
Collection, review and analysis of the monitoring/maintenance parameters during
the vintage year; responsible for monitoring procedures, and for registering the
measured data
Technical team
Responsible of measurements of natural gas consumption and energy
generation
Figure 5. Operational structure of the monitoring plan
v3.2
32
Responsible personnel:
•
The CDM Coordinators supervise the monitoring process and are in charge of compiling the
monitoring data in an excel spreadsheet and calculating the emission reductions of the monitoring
period. They also develop the monitoring report in accordance with the VCS rules.
•
The Plant Manager is responsible for verification of energy measurement. He is responsible for
checking and verifying the meter readings.
•
The Technical Team is responsible meter readings and registering the data in an Excel
spreadsheet.
Personnel who carry out monitoring tasks are familiar with the basic monitoring requirements and
structures. New personnel have to participate in a basic training in order to get familiarized with the
monitoring procedures. Since the main monitoring tasks, i.e. the measurement of the energy production,
the calibration of energy meters, and the reporting of the energy generation, are carried out independently
from the VCS as part of the daily operation, no specific training is required. The VCS Coordinators are
supported by an external consultant if necessary in order to assure correct application of the monitoring
procedures. They also carry out corrective actions if any inconsistency is identified and train the Plant
Manager and the Technical team, if necessary.
5
ENVIRONM ENTAL IM PACT
The law 99 from 1993 provides the general requirements for issuing environmental licenses and permits
and defines the role of the Environmental Ministry and the Regional Autonomous Corporations for the
licensing process.
Article 49 of the law 99 of 1993 and article 3 of the decree 1220 of 2005 indicates that the execution of
works, establishment of industries or the development of any activity that in accordance with the law or
any applicable regulation could produce significant impact on natural resources or the environment or
introduce considerable modifications to the landscape, require an environmental license.
As per articles 8 and 9 of the Decree 2820 of 2010, this cogeneration project does not need to develop an
Environmental Impact Assessment nor an environmental license. Since it is within the limits of the
manufacturing company, it complies with the rules established for the manufacturer and may be operated
under the current operating permission of the plant. Due to the modification of the generation process, an
Environmental Management Plan will be developed.
6
STAKEHOLDER COM M ENTS
As per the VCS rules and since the project is developed within an industrial facility without impacts on
stakeholders, no specific stakeholder consultation was carried out.
v3.2
33

AXIA ENERGIA COGENERATION PROJECT IN UNIBOL

Transcription

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