PDD_Varela Hermanos V1 0

Transcription

PROJECT DESIGN DOCUMENT FORM (CDM-SSC-PDD)
(CDM
- Version 03
CDM – Executive Board
CLEAN DEVELOPMENT MECHANISM
PROJECT DESIGN DOCUMENT FORM (CDM-SSC
(CDM SSC-PDD)
Version 03 - in effect as of: 22 December 2006
CONTENTS
A.
General description of the small scale 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 proposed small scale project activity
Annex 2: Information regarding public funding
fun
Annex 3: Baseline information
Annex 4: Monitoring Information
Annex 5: Tables and Figures.
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Revision history of this document
Version
Number
01
02
03
Date
Description and reason of revision
21 January
2003
8 July 2005
Initial adoption
22 December
2006
•The Board agreed to revise the CDM SSC PDD to reflect guidance
and clarifications provided by the Board since version 01 of this
document.
•As a consequence, the guidelines for completing CDM SSC PDD
have been revised accordingly to version 2. The latest
lates version
can be found at <http://cdm.unfccc.int/Reference/Documents
http://cdm.unfccc.int/Reference/Documents>.
•The Board agreed to revise the CDM project design document for
small-scale activities (CDM-SSC-PDD),
PDD), taking into account
CDM-PDD and CDM-NM.
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SECTION A. General description of small-scale project activity
A.1
Title of the small-scale
scale project activity:
Varela Hermanos. S.A.- Methane recovery & energy generation project
Version 1.0
14/11/2011
A.2.
Description of the small-scale project activity:
The proposed project activity will be carried out in the Hacienda San Isidro distillery of Varela Hermanos.
S.A., which is near the Pesé village,
village province of Herrera in Panamá. Its main purpose is to avoid
avoi methane
emissions from anaerobic degradation of vinasse that is produced as a result of the distillery process.
process
With a current
ent annual production higher than 8 M litres of ethyl alcohol from sugar cane juice and molasses,
molasses
Varela Hermanos generates as a result of its production process, up to 12.65 litres of vinasse per litre of
alcohol produced. This vinasse is sent into open anaerobic lagoons before it is finally irrigated on nearby
plantations. The vinasse is a spent wash with an extremely high pollution
on load. Indeed, given the use of
molasses as a source of raw material for alcohol production, itss chemical oxygen demand (COD) is close to
59,000 mg/l resulting in high methane (CH4) emissions which are currently released to the atmosphere.
atmosphere
Through the CDM project, Varela Hermanos
H
seeks to replace the current wastewater treatment
trea
by the
installation of a low rate anaerobic digestion system. This digestion system will have
ha a COD removal
efficiency of 65%. Afterwards, the spent-wash will be applied as fert-irrigation
irrigation to the nearby agricultural crop
lands.
The project activity will generate 12,696 Nm3 of biogas per day during zafra (harvest) whereas during nonzafra (non-harvest),, this amount will raise to 21,273
21
Nm3/day. The biogas will be filtered and then used to
satisfy the distillery’s energy requirements.
During zafra season the biogas will be used to generate electricity, which will be used on-site,
on
the surplus of
electricity will be fed into the national grid. Out of the zafra season, the biogas will
wi replace 100% of the
current use of heavy fuel oil,, and the excess of electricity will also be exported into
to the grid.
The project activity will reduce GHG emissions in two ways, first by avoiding methane emissions from
anaerobic lagoons and second, by displacing energy generation from the use of heavy fuel oil and fossil fuel
based grid-connected
connected power plants.
plants As a result, it is expected to provide yearly average emissions reductions
of 33,331 tCO2e and 233,320 tCO2e over the first seven-year crediting period.
Main sustainable development benefits
In addition to emission reductions, the contribution to the host country’s sustainable development is significant
in terms of environmental and technical well-being.
well
Environmental impacts
The project will contibute
ontibute to the preservation of natural resources and the environment.
enviro
Specifically the
project:
• Reduces the unpleasant odour from the existing open lagoons,
lag
• Conserves non-renewable
renewable natural resources (fossil fuels) by reducing on-site
on
fossil fuel consumption
and by displacing
cing fossil fuel based grid electricity generation, and
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•
Reduces
educes other local air pollutants such as CO, SOx, PM and NOx associated with the burning of fuel
oil.
Social impacts
The social development benefits that arise from the implementation
implementation of the proposed project activity include:
• A contribution to increase the stability and security of the local power supply, which in turn supports
support
an improved standard of living;
• The creation of new local jobs for the construction and the operation of the plant;
• The impovement of technical knowledge and skills of the plant operators and,
• The closure of the gap between the supply and the demand of electrical power at the national level.
Economic impacts
The project activity provides the following benefits in terms of promoting sustainable economic development:
• Stimulation of employment/earning opportunities for the local people by creating new local jobs;
• Support the increase of power/energy security to the Panamenian grid;
• A decrease of the outflow of foreign
foreign exchange capital by reducing the import of fossil fuels;
fuels and,
• The catering for the growing power demand that is being forecast for Panama.
Panama
Technological impacts
The technology implementation will be developed by UEM Group, an international multi-disciplined
multi
environmental services company specialized in providing turnkey design and construction services in water
and wastewater treatment for industries and municipalities. It has installed over 40 anaerobic wastewater
treatment systems for spent wash treatment
treatment for sugar cane molasses based distilleries.
Therefore, this project will result in the promotion of technology transfer to Panama and will be an example
and a CDM reference for other distilleries and industries interested to develop similar projects.
projec
Conclusion
The proposed project activity will contribute to sustainable development by avoiding methane emissions from
anaerobic lagoons and by substituting a fossil fuel based energy system by a renewable biogas
bio
based energy
system. It will generate environmental benefits not only by reducing greenhouse gas emissions but also by
reducing other local air pollutants associated with the burning of fuel oil. In addition, the project will
contribute to the creation of new jobs and will involve the training of the staff in the operation and
maintenance of new green technologies.
A.3.
Project participants::
Private and/or public entity(ies)
Kindly indicate if the Party involved
project participants (*)
wishes to be considered as project
(as applicable)
participant (Yes/No)
Panama (host country)
Varela Hermanos S.A.
No
(*) In accordance with the CDM modalities and procedures, at the time of making the CDM-PDD
CDM
public at the
stage of validation, a Partyy involved may or may not have provided its approval. At the time of requesting
registration, the approval by the Party(ies) involved is required.
Name of Party involved (*)
(host) indicates a host Party)
Please refer to Annex 1 for more detailed contact information.
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A.4.
Technical description of the small-scale project activity:
A.4.1. Location of the small-scale project activity:
A.4.1.1.
Host Party(ies):
A.4.1.2.
Region/State/Province etc.:
A.4.1.3.
City/Town/Community etc:
Panama
Herrera
Pesé
Details of physical location, including
ncluding information allowing the
A.4.1.4.
unique identification of this small-scale project activity :
The CDM project activity will take place in the Hacienda San Isidro of Varela Hermanos
H
S.A. in Chitré,
province of Herrera, approximately 250 km away from Panama
Pana City.
Precise GPS coordinates for the project are 7°53’57.50”N and 80°35’43.12”W. (Please refer to Figure 1 and
Figure 2¡Error!
¡Error! No se encuentra el origen de la referencia.)
referencia.
Figure 1: Map of Panama
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Anaerobic
Lagoons
Figure 2: The project’s location
A.4.2. Type and category(ies) and technology/measure of the small-scale
small
project activity:
Type and category
he simplified modalities and procedures for small-scale
small scale CDM project activities,
According to Appendix B to the
the project type, category and sectoral scope are determined as follows:
Methane recovery component:
Type III: Other project activities
Category III.H: Methane Recovery in Wastewater
Was
Treatment
Sectoral Scope 13: Waste handling and disposal
Energy generation component:
Type I: Renewable energy projects
Category I.C: Thermal energy production with or without electricity.
Sectoral Scope 1: Energy industries (renewable /non-renewable
/non
sources)
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Technology of the small-scale
scale project activity
Current situation and project activity specifications are detailed below:
Ethanol production
Varela Hermanos produces ethanol from cane juice and molasses. The distillery is operating around 200 days
per year and has a production capacity of 50,000
5
litres of ethanol/day.
As a result of its production process, Varela Hermanos
H
generates 12.65 litres of vinasse per litre of alcohol
produced.
The volume of vinasse associated with the ethanol production is expected to rise in the future due to plans for
increased alcohol production at the distillery; the forecast estimation is presented in Table 1¡Error! No se
encuentra el origen de la referencia.:
Alcohol Prod.
(M l/year)
Vinasse
(m3/year)
2011
2012
2013
2014
2015
2016
2017
2018
2019
8.76
9.23
9.79
10.44
10.44
10.44
10.44
10.44
10.44
110,814
116,765
123,849
132,066
132,066
132,066
132,066
132,066
132,066
Table 1: Planning data for alcohol production
Existing wastewater treatment
The effluent of the distillery, the vinasse,
vinasse is a highly polluted wastewater, which is currently treated as follows:
first vinasse is directed to a storage lagoon from which it is disposed in four identical anaerobic
a
lagoons
(please refer to Table 2).. Finally, vinasses are used as fertilizer on nearby plantations.
plantations The specific amount of
vinasse is 12.65 litres/litres of ethanol with a very high COD concentration.
Below are some pictures
res of the current anaerobic lagoons:
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Figure 3: Vinasse anaerobic lagoons
The following table describes the current anaerobic lagoons
lagoon characteristics:
Lagoon
Area (Ha)
Max. Depth (m)
Type
1
2.2
Approx. 3.0
Anaerobic
2
1.2
3.0
Anaerobic
3
1.2
3.0
Anaerobic
4
1.2
3.0
Anaerobic
5
1.2
3.0
Table 2: Current anaerobic ponds characteristics
Anaerobic
Current energy situation
During the zafra
afra season, which goes from January to May, Varela Hermanos
H
s uses bagasse and biomass
residues from the sugar cane plantations1 as fuel in two boilers of 21,500 lbs/hr at 150 psi. Whereas, out of the
zafra season (June-December),
December), the distillery uses bunker fuel as fuel in a boiler of 21,000 lbs/hr at 150 psi. The
amount of bunker used is 5,000 litres/day.
The electricity consumption by the distillery
d
is:
2011: for 7 months period average electricity use is 1,085 kW
k
2010: for 12 month period average electricity use is 485 kW
k
2009: for 12 month period average
a
electricity use is 476 kW
Project activity description
The project activity involves the installation of a biogas plant for power generation based on a low rate
anaerobic digester; this plant will replace the current wastewater treatment based on anaerobic lagoons. The
new process is shown in the following figure:
1
The emissions reductions due to the use of biomass for energy requirements are not claimed as part as the proposed
project activity.
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Figure 4:: Flow diagram of the biogas digester system
The spent wash from the distillery will be taken as currently to one of the lagoons sized to provide 1,500 m3
retention
ntion time at 1.5 meter depth (to be provided by distillery) or alternatively UEM will build a cooling
system to bring down the temperature from 80 °C to 40 °C.
C. The cooled vinasse is then
th conveyed via pumps to
the digester.
The cooled spent wash will then
then be pumped via stainless steel (wetted parts) transfer pumps into the Low Rate
Anaerobic Digesters. The technology provider, UEM, proposes the following configuration of the anaerobic
digesters: two digesters or one digester with a total capacity of 17,143 m3. The digesters shall be in bolted steel
design with a concrete foundation and floor design and will have durable floating membrane covers.
The inlet distribution header will be spread over the entire width of the reactor on the inlet side. Slow speed
spee
mixing will be provided in each digester to keep the digester contents well mixed and in suspension. Each
digester will be designed for a large HRT (Hydraulic Retention Time).. The large volume allows the digester to
handle large organic loads and to digest
digest accumulated sludge, resulting in a higher biogas generation. Sludge
will be recycled from the bottom of the digester from the end to the inlet header, where it will mix with the
incoming spent lees. This serves to recycle the alkalinity created in the digester
digester and to neutralize the incoming
spent wash. The sludge recycle system provides improved biomass-substrate
biomass substrate contact. It also provides for
positive sludge removal; however; this is an infrequent operation,
operation, since the digesters design’s provides long
solids retention times (SRT), and therefore, the quantity of excess sludge generation is low. The large volume
of reactor coupled with the very large mass of sludge, helps in handling shock loading. There shall be no
sludge removal on a daily basis since most of the organic volatile solids will be digested in the digester to help
produce additional biogas.
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Treated wastewater will be withdrawn from the reactor through a Gas Liquid Solid Separator system via an
outlet header. Biogas is removed via a duplex blower
blower system that applies a slight negative pressure beneath the
floating membrane cover while discharging the biogas under pressure to be used either in the boilers or in the
biogas engines. Electricity shall be supplied in the distillery for its captive use
use and balance electricity shall be
supplied to the grid for sale by the distillery. No separate gasholder is required, as excess biogas can be
temporarily stored under the large floating cover if required for a few hours duration. It is worth mentioning
that in case of emergency, the biogas will be sent to an enclosed flare system.
The Anaerobic Digester treatment is expected to provide the following removal efficiencies and performance:
Parameter
% Removal Expected
90%
65-67% during Non Zafra
COD
70% during Zafra
TSS (organic volatile)
70%
Table 3: The digesters removal efficiencies
BOD
The pH of the digestate will be neutral and the temperature of the
the digestate will be around 40 °C.
° All other
parameters will remain similar to the influent which will be discharged for fert-irrigation.
irrigation.
The process can be summarized as follows:
1. Preliminary treatment:
- Cooling of the spent wash via a cooling tower or cooling/settling tank
- Transfer of the cooled spent wash into the low rate anaerobic
anaerobic digester by digester feed pumps
2. Anaerobic biological treatment system:
- Anaerobic biological treatment in a large volume low rate anaerobic digester
- Sludge recycle system to increase solids retention time and recycle alkalinity
- Methane-rich
rich biogas generation
generation and collection in the low rate anaerobic digester
- Biogas pressurization and transmission to point of utilization or to a flare via a biogas
pipeline and safety system
3. Biogas treatment and power generation.
Gas utilization/energy saving
The recovered and cleaned biogas will be used in a power plant comprised of two internal combustion engine
generators that when operating at 100% load shall provide approximately 1,192 KW of gross electricity at 3
phases.. The power plant shall be pre-packaged
pre
and modular
ar in nature to allow for a minimized site installation.
It will be comprised of modules that when re-assembled
re assembled on site will comprise a fully operational plant. The
plant has been configured to separate the mechanical and electrical spaces and allows for maximum
m
accessibility for maintenance within the plant enclosure.
enclosure It shall include all required equipment to allow for the
proper operation of the internal combustion engine-generator
engine generator sets operating on biogas. The biogas and power
plant’s captive electrical consumption shall be utilized from the electricity generation and net exportable
electricity to the grid during the zafra and Non zafra season.
Environmental aspects
This is a new and environmentally safe technology that will lead to a sound wastewater treatment
t
and a
significant reduction of greenhouse gas emissions, odours and pollutants associated with fossil fuel
combustion. Indeed, the design of the digestion system allows the treatment of the vinasse in a much more
efficient way.
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Technology transfer
The
he technology implementation will be developed by UEM Group, a Florida-based
based (USA) engineering firm
which has installed over 40 anaerobic wastewater treatment systems for spent wash treatment for sugar cane
molasses based distilleries.
The materials and labour used in the project activity will be sourced from the host country whenever
economically and technically feasible. When not feasible, the materials and labour will be sourced from Annex
1 countries.
A.4.3
Estimated amount of emission reductions
reduction over the chosen crediting period:
period
Once implemented, it is estimated that the Project will reduce 33,331 tCO2e annually, generating an expected
total of 233,320 tCO2e for the duration of the first renewable seven year crediting period.
period
The Project’s estimated annual emission reductions over the first crediting period are as follows:
Years
2013
201
201
2014
201
2015
201
2016
201
2017
201
2018
2019
Total emission reductions (tonnes of CO2)
Total number of crediting years
Annual average over the crediting period of estimated
reductions (tonnes of CO2)
Annual estimation of emission
reductions in tonnes of CO2
32,092
33,538
33,538
33,538
33,538
33,538
33,538
233,320
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33,331
A.4.4. Public funding of the small-scale project activity:
This project will not receive any
an public funding from Annex I Parties.
A.4.5. Confirmation that the small-scale project activity is not a debundled component of a
large scale project activity:
As per Appendix C of the Simplified Modalities and Procedures for Small-Scale
Small Scale CDM Project Activities - “A
proposed small-scale
scale project activity shall be deemed to be a debundled component of a large project activity
if there is a registered small-scale
scale CDM project activity or an application to register another small-scale
small
CDM
project activity:
(a) With the same project participants;
(b) In the same project category and technology/measure;
(c) Registered within the previous 2 years; and
(d) Whose project boundary is within 1 km of the project boundary of the proposed small-scale
small
activity at the closest
losest point.”
point
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The proposed project activity is not a debundled component of a large project activity as there is no small-scale
small
CDM project activity or an application registered in the same project category and technology/measure in the
last two years within
thin 1 km of the project boundary of the proposed small-scale
small scale 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
small-scale project activity::
The following approved baseline and monitoring methodologies and relevant tools are applied to the proposed
CDM project activity.
• Methane recovery component:
Title of the approved baseline and monitoring methodology: AMS-III.H.
III.H. “Methane Recovery in
Wastewater Treatment” (Version 16,
16 EB 58)
• Energyy generation component:
Title of the approved baseline and monitoring methodology: AMS-I.C. “Thermal
Thermal energy production with
or without electricity” (Version 19, EB 61)
References:
Approved baseline
ine and monitoring methodology AMS-I.D
AMS
(Version 17, EB 61), used to calculate the baseline
for supply of electricity and/or displacement electricity from the national grid
“Tool
Tool to calculate the emission factor for an electricity system” (Version 02.2.1,
.1, EB
E 63), used to calculate the
emission factor.
“Tool to determine project emissions from flaring gases containing methane” (Annex 13, EB 28), used to
calculate methane emissions due to incomplete flaring.
“Tool to determine methane emissions avoided from disposal
disposal of waste at a solid waste disposal site” (Version
04, EB 41), this tool is not applicable since the project activity does not involve the disposal of waste at a solid
waste disposal.
“Tool to calculate project or leakage CO2 emissions from fossil fuel combustion” (Version 2, EB 41), this tool
is not applicable since the project activity does not involve any fossil fuel combustion.
B.2
Justification of the choice of the project category:
AMS-III.H (Version 16)) is applicable to the methane recovery component of the project activities as shown
in the following table.
Ref.1
(*)
AMS-III.H
“This methodology comprises measures that recover biogas from biogenic organic
matter in wastewater by means of one, or a combination, of the following options:
…
(d) Introduction of biogas recovery and combustion to an anaerobic wastewater
treatment system such as anaerobic reactor, lagoon, septic tank or an onsite industrial
plant.”
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Project
Activity
AMS-III.H
Ref.2
(*)
Project
Activity
Ref.3
(*)
Ref.4
(*)
AMS-III.H
“The recovered biogas from the above measures may also be utilised for the following
applications instead of combustion/flaring:
(a) Thermal or mechanical, electrical energy generation directly;…”
Project
Activity
The project
proj is covered under paragraph 3(a).
The recovered
recove
methane is utilized directly for thermal and electrical energy generation.
AMS-III.H
“If the recovered biogas is used for project activities covered under paragraph 3 (a),
that component of the project
project activity can use a corresponding methodology under
Type I.”
Project
Activity
The approved baseline and monitoring methodology AMS I.C.
I. is used for the energy
generation component of the project activity.
AMS-III.H
Ref.5
(*)
Project
Activity
“For project activities covered
covered under paragraph 3(b), if bottles with upgraded biogas
are sold outside the project boundary, the end-use
end use of the biogas shall be ensured via a
contract between the bottled biogas vendor and the end-user.
end user. No emission reductions
may be claimed from the displacement of fuels from the end use of bottled biogas in
such situations. If however the end use of the bottled biogas is included in the project
boundary and is monitored during the crediting period CO2 emissions avoided by the
displacement of fossil fuel can be claimed under the corresponding Type I
methodology, e.g. AMS-I.C
AMS I.C .Thermal energy production with or without electricity”.
This condition is not applicable to the project activity since it is covered under
paragraph 3(a) and not
n covered under paragraph 3(b)
AMS-III.H
“For project activities covered under paragraph 3(c)(i), emission reductions from the
displacement of the use of natural gas are eligible under this methodology, provided
the geographical extent of the natural
natural gas distribution grid is within the host country
boundaries.”
Project
Activity
This condition is not applicable to the project activity since it is covered under
paragraph 3(a) and not under paragraph 3(c)(i).
AMS-III.H
“For project activities
activities covered under paragraph 3(c)(ii), emission reductions for the
displacement of the use of fuels can be claimed following the provision in the
corresponding Type I methodology, e.g. AMS-I.C.”
AMS
Ref.6
(*)
Ref.7
(*)
The project activity consists in the substitution of the existing open anaerobic lagoons
by the installation of an anaerobic digestion system that will allow capturing the
methane emissions.
“In cases where baseline system is anaerobic lagoon the methodology is applicable if:
(a) The lagoons are ponds with a depth greater than two meters, without aeration. The
value for depth is obtained from engineering design documents, or through direct
measurement, or by dividing the surface area by the total volume. If the lagoon filling
level varies seasonally, the
the average of the highest and lowest levels may be taken;
(b) Ambient temperature above 15°C, at least during part of the year, on a monthly
average basis;
(c) The minimum interval between two consecutive sludge removal events shall be 30
days.”
The baseline system is an anaerobic lagoon with a depth greater than two meters
(Please refer to SectionA.2Table 2). The ambient temperature is above 15°C; and the
interval between two consecutives sludge removal is greater than one month.
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Project
Activity
This condition is not applicable to the project
project activity since it is covered under
paragraph 3(a) and not under paragraph 3(c)(ii).
AMS-III.H
“In particular, for the case of 3(b) and (c) (iii), the physical leakage during storage
and transportation of upgraded biogas, as well as the emissions
emi
from fossil fuel
consumed by vehicles for transporting biogas shall be considered. Relevant procedures
in paragraph 11 of Annex 1 of AMS-III.H
AMS III.H “Methane recovery in wastewater treatment”
shall be followed in this regard.”
Project
Activity
This condition
condition is not applicable to the project activity since it is covered under
paragraph 3(a) and not under paragraphs 3(b) and (c) (iii).
AMS-III.H
“For project activities covered under paragraph 3 (b) and (c), this methodology is
applicable if the upgraded
upgraded methane content of the biogas is in accordance with
relevant national regulations (where these exist) or, in the absence of national
regulations, a minimum of 96% (by volume).”
Project
Activity
This condition is not applicable to the project activity
activity since it is covered under
paragraph 3(a) and not under paragraphs 3(b) and (c).
AMS-III.H
“If the recovered biogas is utilized for production of hydrogen (project activities
covered under paragraph 3(d)), that component of project activity
activit shall use
corresponding category AMS-III.O
AMS
“Hydrogen production using methane extracted
from biogas”.
Project
Activity
This
his condition is not applicable to the
t project activity since it is covered under
paragraph 3(a) and not under paragraph 3(d).
AMS-III.H
“If
If the recovered biogas is used for project activities covered under paragraph 3 (e),
that component of the project activity shall use corresponding methodology AMSAMS
III.AQ “Introduction of Bio-CNG
Bio
in road transportation”.
Project
Activity
This
his condition is not applicable to the
t project activity since it is covered under
paragraph 3(a) and not under paragraph 3(e).
3
AMS-III.H
“New facilities (Greenfield projects) and project activities involving a change of
equipment resulting
resulting in a capacity addition of the wastewater or sludge treatment
system compared to the designed capacity of the baseline treatment system are only
eligible to apply this methodology if they comply with the requirements in the General
Guidance for SSC methodologies4
methodologies4 concerning these topics. In addition the
requirements for demonstration of the remaining lifetime of the equipment replaced as
described in the general guidance shall be followed.”
Project
Activity
The project is not a Greenfield project and it does not result in a capacity addition of
the wastewater or sludge treatment capacity.
Ref.8
(*)
Ref.9
(*)
Ref.
10
(*)
Ref.
11
(*)
Ref.
12
(*)
Ref.
13
(*)
AMS-III.H
Project
Activity
“The location of the wastewater treatment plant shall be uniquely defined as well as
the source generating the wastewater and described in the PDD.”
PDD
The location of the wastewater treatment plant as well as the generation source of the
wastewater are uniquely defined and described in this PDD. (Please refer to Section
A.4.1.4.)
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Ref.
14
(*)
AMS-III.H
“Measures are limited to those that result in aggregate emission reductions of less than
or equal to 60 ktCO
kt 2 equivalent annually from all Type III components of the project
activity.”
Project
Activity
The ex--ante annual emission reductions achieved by the methane recovery component
of the project are estimated to be 23 ktCO2e, which is less than 60 ktCO2e.
*Reference paragraph number in “technology/
“technology measure” section (AMS-III.H
.H methodology)
Table 4:: Assessment of applicability criteria for the methane recovery component.
AMS-I.C (Version 19)) is applicable to the energy generation component of the project activities as shown in
the following table:
AMS-I.C
“This methodology comprises renewable energy technologies that supply users with
thermal energy that displaces fossil fuel use. These units include technologies such as
solar thermal water heaters and dryers, solar cookers, energy derived from renewable
biomass and other technologies that provide thermal energy that displaces fossil fuel”.
Project
Activity
The project consists in the use of biogas to replace fossil fuel consumption used to
satisfy the thermal energy requirements of the distillery.
distillery
AMS-I.C
Biomass-based
Biomass
based cogeneration systems consisting are included in this category. For the
purpose of this methodology “cogeneration” shall mean the simultaneous generation
of thermal energy and electrical energy in one process. Project activities that produce
heat and power in separate element processes (for example, heat from a boiler and
electricity
tricity from biogas engine) do not fit under the definition of cogeneration project.
project
Project
Activity
This condition is not applicable to the project activity as it does not involve the
installation of a biomass-based
biomass
cogeneration system.
AMS-I.C
Emission reductions from a biomass cogeneration system can accrue from one of the
following activities:
a) Electricity supply to a grid;
b) Electricity and/or thermal energy (steam or heat) production for on-site
on
consumption or for consumption by other facilities;
ities;
c) Combination of (a) and (b).
Project
Activity
biomass
AMS-I.C
The total installed/rated thermal energy generation
generation capacity of the project equipment
is equal to or less than 45 MW thermal. 2
Project
Activity
The total thermal capacity of the boiler is 6.3 MWth and has been determined by taking
the difference between enthalpy of total output leaving the project equipment and the
total enthalpy of input of feed water entering the boiler.
Ref.1
(*)
Ref.2
(*)
Ref.3
(*)
Ref.4
(*)
2
Thermal energy generation capacity shall be manufacturer’s
manufacturer’s rated thermal energy output, or if that rating is not
available the capacity shall be determined by taking the difference between enthalpy of total output (for example
steam or hot air in kcal/kg or kcal/m3) leaving the project equipment and the total enthalpy of input (for example
feed water or air in kcal/kg or kcal/m3) entering the project equipment. For boilers, condensate return (if any) must
be incorporated into enthalpy of the feed.
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AMS-I.C
Ref.5
(*)
Project
Activity
AMS-I.C
Ref.6
(*)
For co-fired
-fired
fired systems, the total installed thermal energy generation capacity of the
project equipment, when using both fossil and renewable fuel shall not exceed
exce 45 MW
thermal
The project activity does not involve the use of both fossil and renewable fuel.
Moreover, since the thermal capacity of the boiler is 6.3MWth, this condition is
fulfilled.
The following capacity limits
limits apply for biomass cogeneration units:
(a) If the project activity includes emission
emission reductions from both thermal and
electrical energy components, the total installed energy generation capacity
(thermal and electrical) of the project equipment shall not
n exceed 45 MW
thermal. For the purpose of calculating this capacity limit the conversion
factor of 1:3 shall be used for converting electrical energy to thermal
energy (i.e., for renewable energy project activities, the maximal limit of 15
MW(e) is equivalent
alent to 45 MW thermal output of the equipment or the
plant);
(b) If the emission reductions of the cogeneration project activity are solely on
account of thermal energy production (i.e., no emission reductions accrue
from electricity component), the totall installed thermal energy production
capacity of the project equipment of the cogeneration unit shall not exceed
45 MW thermal;
(c) If the emission reductions of the cogeneration project activity are solely on
account of electrical energy production (i.e.,., no emission reductions accrue
from thermal energy component), the total installed electrical energy
generation capacity of the project equipment of the cogeneration unit shall
not exceed 15 MW.
Project
Activity
biomass
AMS-I.C
The capacity limits specified in the above paragraphs apply to both new facilities and
retrofit projects In the case of project activities that
that involve the addition of renewable
energy units at an existing renewable energy facility, the total capacity of the units
added by the project should comply with capacity limits in paragraphs 4 to 6, and
should be physically distinct from existing units.
units
Project
Activity
This condition does not apply to the project activity since it does not involve the
addition of renewable energy units at an existing renewable energy facility.
AMS-I.C
Project activities that seek to retrofit or modify an existing
existing facility for renewable
energy generation are included in this category.
Project
Activity
The project activity seeks to modify an existing facility for renewable energy
generation Thus, it is included in this category.
generation.
AMS-I.C
New Facilities
Facilities (Greenfield projects) and project activities involving capacity additions
compared to the baseline scenario are only eligible if they comply with the related and
relevant requirements in the “General Guidelines to SSC CDM methodologies”.
Ref.7
(*)
Ref.8
(*)
Ref.9
(*)
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Ref.
10
(*)
Ref.
11
(*)
Ref.
12
(*)
Project
Activity
The project activity complies with all relevant requirements in the “General Guidelines
to SSC CDM methodologies”.
AMS-I.C
If solid biomass fuel (e.g. briquette) is used, it shall be demonstrated that it has been
produced using solely renewable
renewable biomass and all project or leakage emissions
associated with its production shall be taken into account in the emissions reduction
calculation.
Project
Activity
The project activity does not involve the use of solid biomass fuel. Thus, this condition
condi
is not applicable.
AMS-I.C
Where the project participant is not the producer of the processed solid biomass fuel,
the project participant and the producer are bound by a contract that shall enable the
project participant to monitor the source
source of the renewable biomass to account for any
emissions associated with solid biomass fuel production. Such a contract shall also
ensure that there is no double-counting
double counting of emission reductions.
reductions
Project
Activity
As stated above, the project activity does
does not involve the use of solid biomass fuel.
Thus, this condition is not applicable.
AMS-I.C
If electricity and/or steam/heat produced by the project activity is delivered to a third
party i.e. another facility or facilities within the project
project boundary, a contract between
the supplier and consumer(s) of the energy will have to be entered into that ensures
there is no double-counting
double
of emission reductions.
Project
Activity
This condition does not apply since all the steam produced will be used for on-site
requirements.
AMS-I.C
Ref.
13
(*)
Project
Activity
Ref.
14
(*)
AMS-I.C
If the project activity recovers and utilizes biogas for power/heat production and
applies this methodology on a stand-alone
stand alone basis i.e. without using a Type III
component of a SSC methodology, any incremental
incremental emissions occurring due to the
implementation of the project activity (e.g. physical leakage of the anaerobic digester,
emissions due to inefficiency of the flaring), shall be taken into account either as
project or leakage emissions.
This condition does not apply to project activity since this methodology is not applied
on a stand-alone
stand alone basis. All incremental emissions occurring due to the implementation
of the project activity will be taken into account following the procedures stated
stat in the
approved methodology AMS-III.H.
AMS
Charcoal based biomass energy generation project activities are eligible to apply the
methodology only if the charcoal is produced from renewable biomass sources
provided:
(a) Charcoal is produced
produced in kilns equipped with methane recovery and destruction
facility; or
(b) If charcoal is produced in kilns not equipped with a methane recovery and
destruction facility, methane emissions from the production of charcoal shall be
considered. These emissions
emissions shall be calculated as per the procedures defined in the
approved methodology AMS-III.K.
AMS III.K. Alternatively, conservative emission factor values
from peer reviewed literature or from a registered CDM project activity can be used,
provided that it can be demonstrated
demonstrated that the parameters from these are comparable
e.g. source of biomass, characteristics of biomass such as moisture, carbon content,
type of kiln, operating conditions such as ambient temperature.
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This condition does not apply to the project activity since it does not involve the use of
charcoal biomass.
Project
Activity
*Reference paragraph number in “technology/
“technology measure” section (AMS-I.C
I.C methodology)
Table 5: Assessment of applicability criteria for the electricity generation
ation component.
component
B.3.
Description of the project boundary:
Next diagram illustrates the project boundary:
Project boundary
Energyy generation component
Methane recovery component
Vinasses
Alcohol production
Steam
Cooling process
Boiler
Methane capture
in biodigesters
Biogas
purification
Flare (for
emergency)
Biogas
engines
Aerobic lagoons
Electri
city
Spent
wash
Used for irrigation in nearby
plantations, in accordance to
national discharge standards.
Used for on-site
site consumption and
surplus will be exported to the
national grid
Figure 5:: Conceptual diagram of the boundary of the project
Emissions by sources:
The table below indicates GHG emissions
emissions that are considered in the proposed CDM project activity:
Baseline
Source
Wastewater
treatment
processes
Gas
Included/Excluded
CO2
Excluded
CH4
Included
18
Justification/Explanation
CO2 emissions from the decomposition of
organic waste are not accounted for. This
Th is
conservative.
Main source of emissions in the baseline from
open lagoons.
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Project Activity
Energy
generation
Wastewater
treatment
processes
Energy
generation
B.4.
N 2O
Excluded
CO2
Included
CH4
Excluded
N 2O
Excluded
CO2
Excluded
CH4
Included
N 2O
Excluded
CO2
Excluded
CH4
Excluded
N 2O
Excluded
Excluded
for
simplification.
This
is
conservative.
Main emission source. Biogas captured is used
to generate electricity
ectricity to replace fossil fuels and
grid electricity.
Excluded
for
simplification.
This
is
conservative.
Excluded
for
simplification.
This
is
conservative.
CO2 emissions from the decomposition of
organic waste are not accounted for.
Main emission source. Emissions through
degradable organic carbon in treated wastewater,
fugitive emissions from biogas release in capture
system and emissions from incomplete
i
flaring
are accounted for.
Excluded for simplification. This emission
source is assumed to be very small.
The energy requirements will be fulfilled by the
use of the recovered biogas.
Description of baseline and its development:
development
Identification of the baseline scenarios
• Methane recovery component
The
he baseline scenario for the methane emissions avoidance is the existing anaerobic wastewater treatment
system without methane recovery and combustion. As stated in the Section A.4.2,
A.4.2 the existing wastewater
treatment system is based on open deep anaerobic lagoons, which are the source of baseline methane (CH4)
emissions. The project activity introduces an anaerobic digestion system with biogas recovery and combustion
thus avoiding the emission of methane into
int the atmosphere from the open lagoon.
Data used to determine the baseline is provided in the table below:
Data/Parameter
Volume of vinasse (m3/year)
COD inflow to the baseline wastewater
treatment (tonnes/m3)
COD removal efficiency of the baseline
treatment system
Methane generationn capacity of wastewater
(kg CH4/kg COD)
Symbol
Value
Qww,y
See Table 1
COD inflow, i, y
58,441
Measurement campaign
η COD,BL,i
88.74%
Calculated as per
measurement campaign
Bo,ww
0.25
IPCC
19
Source of data
Distillery design
specifications
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Methane correction factor for the existing
anaerobic
deep
lagoon
wastewater
MCFww,treat,BL,i
0.8
As per table III.H.1
treatment system
Model correction factor
UFBL
0.89
AMS-III.H
Global Warming Potential for methane
GWPCH4
21
AMS-III.H
Table 6:: Parameters used to determine the methane recovery component baseline
Compliance with the national regulations
There is no specific restriction or regulation preventing the use of open
open anaerobic lagoons in Panama.
Indeed, the industries shall fulfill the industrial wastewater discharge standard which allows controlling the
quality of industrial wastewaters before being discharged into a water body such as rivers or lakes.
Accordingg to these statements, Varela Hermanos does not have any obligation to replace the current treatment
system and consequently, the baseline scenario is the continuation of the current practice,
practice thus the use of open
anaerobic lagoons.
• Energy generation component:
onent:
As per paragraph 19 of the approved methodology
methodolog AMS I.C (Version 19), project activities producing both
heat and electricity shall use one of the following baseline scenarios:
(a) Electricity is imported from a grid and thermal energy (steam/heat) is produced
produced using fossil fuel;
(b) Electricity is produced in an on-site
on site captive power plant using fossil (with a possibility of export to the
grid) and thermal energy (steam/heat) is produced using fossil fuel;
(c) A combination of (a) and (b);
(d) Electricity and thermal
al energy (steam/heat) are produced in a cogeneration unit using fossil fuel (with
a possibility of export of electricity to a grid/other facilities and/or thermal energy to other facilities);
(e) Electricity is imported from a grid and/or produced in an on-site
on ite captive power plant using fossil fuels
(with a possibility of export to the grid); steam/heat is produced from biomass;
(f) Electricity is produced in an on-site
on site captive power plant using biomass (with a possibility of export to
a grid) and/or imported from
from a grid; steam/heat is produced using fossil fuel;
(g) Electricity and thermal energy (steam/heat) are produced in a biomass fired cogeneration unit (without
a possibility of export of electricity either to a grid or to other facilities and without a possibility
possib
of
export of thermal energy to other facilities). This scenario applies to a project activity that installs a
new grid connected biomass cogeneration system that produces surplus electricity and this surplus
electricity is exported to a grid. The baseline
baseline scenario is that the electricity would otherwise have been
generated by the operation of grid-connected
grid connected power plants and by the addition of new generation
sources to the grid;
(h) Electricity and/or thermal energy produced in a co-fired
co
system;
(i) Electricity
city is imported from a grid and/or produced in a biomass fired cogeneration unit (without a
possibility of export of electricity either to the grid or to other facilities); steam/heat is produced in a
biomass fired cogeneration unit and/or a biomass fired boiler (without a possibility of export of
thermal energy to other facilities). This scenario applies to a project activity that installs a new
biomass cogeneration system that displaces electricity which otherwise would have been imported
from a grid.
Besides
esides avoiding methane emissions from the anaerobic lagoons,
lagoon , the project aims at replacing the bunker used
in one of the boilers and producing electricity to satisfy the on-site
on site requirements, thus avoiding its importation
from the National Grid. The surplus
surplus of electricity will be exported to the National Grid. In this manner, the
project contributes directly to reduce GHG emissions as it produces heat and electricity from a renewable
source.
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Therefore, the baseline scenario is option (a), which is the current
cur
practice.
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 small-scale
scale CDM project activity:
In accordance with the simplified modalities and procedures
proc
for small-scale
scale CDM project activities, a
simplified baseline and monitoring methodology listed in Appendix B may be used for a small-scale
small
CDM
project activity if project participants are able to demonstrate to a designated operational entity that the project
activity would otherwise not be implemented due to the existence of one or more barrier(s) listed in
Attachment A of Appendix B.
“Project participants shall provide an explanation to show that the project activity would not have occurred
anywayy due to at least one of the following barriers:
(a) Investment barrier:: a financially more viable alternative to the project activity would have led to
higher emissions;
(b) Access-to-finance
finance barrier:
barrier: the project activity could not access appropriate capital without
wit
consideration of the CDM revenues;
(c) Technological barrier:
barrier: a less technologically advanced alternative to the project activity involves
lower risks due to the performance uncertainty or low market share of the new technology adopted for
the project activity
ivity and so would have led to higher emissions;
(d) Barrier due to prevailing practice:
practice: prevailing practice or existing regulatory or policy requirements
would have led to implementation of a technology with higher emissions;
(e) Other barriers such as institutional
institutional barriers or limited information, managerial resources,
organizational capacity, or capacity to absorb new technologies.”
The additionality argument is based on the proposition that the project faces an investment barrier that prevents
the implementation
on of this type of project activity.
Investment barrier
The project faces a barrier to implementation due to the poor returns on investment. To illustrate this, an
investment analysis to demonstrate that the proposed project activity is not economically or financially feasible
without the revenue from the sale of Certified Emission Reductions (CERs) has been performed.
Based on the fact that the proposed project activity generates financial and economic benefits trough the sales
of electricity and savingss from bunker displacement, other that CERs related income,
income the benchmark analysis
has been determined as an appropriate analysis method.
For that reason, the default expected return on equity for Group 1 in the CDM Guidelines for Investment
Analysis3 has been selected. Thus, the IRR benchmark is 12%.
All key financial parameters were estimated by UEM Group 4 (the technology provider).
provider) Moreover, the cash
flow was prepared for a plant life time of 20 years,, which was indicated by the technology provider.
provider
The project IRRs with and without the CERs sales revenue are shown in Table 7.
3
http://cdm.unfccc.int/Reference/Guidclarif/reg/reg_guid03.pdf
4
Please refer to “Technical Details for Varela Hermanos Destillery, Panama”.
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IRR
Without CERs revenues
9.99%
With CERs revenues
14.55%
Table 7:: Impact of CERs revenues on the Proposed
Proposed Project’s IRR
Table 7 7 shows that the IRR of the total investment of the proposed project without CERs sales revenue is
9.99%,
%, lower than the benchmark IRR of 12%, which means that the proposed project activity indeed faces
significant financial barriers. Therefore, the project activity is not the most economically or financially
attractive choice of investment.
A sensitivity analysis has been conducted to check whether the financial attractiveness remains unaltered
unal
by
reasonable variations in the critical assumptions. The following parameters were used as critical assumptions:
• CAPEX
• Total savings
• OPEX
fluctu from -10%
10% to +10%.
Table 88 shows the variation of IRR when the three parameters fluctuate
-10%
-5%
0%
+5%
+10%
CAPEX
8.62%
9.28%
9.99%
10.75%
11.59%
Total savings
11.68%
10.84%
9.99%
9.11%
8.22%
OPEX
9.73%
9.86%
9.99%
10.11%
10.24%
Table 8: IRR fluctuation
12,00%
11,50%
11,00%
10,50%
10,00%
9,50%
9,00%
8,50%
8,00%
7,50%
7,00%
10%
5%
CAPEX
0%
-5%
SAVINGS
OPEX
Figure 6: IRR fluctuation
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Sensitivity analysis has been carried out for the stated costs and assumptions. It shows that under none of those
scenarios the IRR of thee project exceeds the Benchmark5.
It is not considered likely that the project’s return will exceed the benchmark,, since as stated above, all key
financial figures were provided by UEM Group, who has a vast experience in developing this kind of projects.
It is worth mentioning that inn the current situation the distillery is in compliance with wastewater
wastewat regulations
and thus, there is no obligation to undertake a new treatment method for vinasses. Actually, at the present time,
there is no barrier which prevents the continuation of the current practice, based on open anaerobic lagoon
treatment and the use
se of bunker fuel in boilers.
boilers
Moreover, this project was thought
though as a CDM project from its conception and the benefits obtained from the
CDM are the main driver that encouraged Varela Hermanos to develop the proposed project activity. Indeed,
Varela Hermanos’
nos’ board decided to execute the project subject to obtaining the CDM Registration, since
thanks to carbon credits’ contribution,
contribution the project risks are reduced and the overall project financial balance
results in an acceptable profitability6.
Conclusion
There is a strong financial barrier that prevents
prevent the implementation of the proposed project activity without the
CDM incentive.
The standardization of the project as a CDM project activity, and the corresponding benefits resulting from the
CERs sale, will
ll help to overcome the identified barrier and thus enable the project to be undertaken.
Early Consideration of CDM
Early consideration of CDM in the decision to undertake the project as CDM project activity by the project
developer can be shown through the
t project implementation schedule as follows:
Events and action
Project idea and proposal from ecosur america
to Varela Hermanos’ representatives
Date
th
14 Feb 2011
Confirmed interest from Varela Hermanos
17th March 2011
CDM potential assessment
17th March 2011
COD measurement campaign
11th June 2011
Validation services offer request to RINA
24th July 2011
Project’ss presentation by ecosur america to
Varela Hermanos’ Board of Directors
25th July 2011
CDM services offer
28th July 2011
Site-visit IBS-UEM Group
5
10th August 2011
Evidence provided to the DOE
E-mail
mail from ecosur america to Varela
Hermanos
E-mail
mail sent by Varela Hermanos to
ecosur america
E-mail+ questionnaire sent by ecosur
america to Varela Hermanos
E-mail
mail between Varela Hermanos and
Aquatec
E-mail
mail between ecosur america and
RINA
E-mails
mails between ecosur America and
Varela Hermanos/ Power-point
Power
presentation.
ecosur america’s
america services offer / e-mails
ecosur america to Varela Hermanos.
e-mailss between IBS, UEM, ecosur
america and Varela Hermanos/
Hermanos plane
tickets
All financial data and calculations will be provided to the DOE.
6
A letter from Varela Hermanos
nos’’ board confirming the necessity of carbon credits to develop the project activity is
available to DOE consultation.
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Offer received from RINA
EIA from Bethesda S.A. to Varela Hermanos
UEM pre-conclusions
conclusions on the site visit/ prepr
conclusions on the project’ss feasibility
Contract signature ecosur America-Varela
America
Hermanos
Invitation to LSC
Prior consideration sent to UNFCCC + DNA
Local Stakeholders’ Consultation
RINA contract signature with Varela Hermanos
GSP expected start date
B.6.
16th August 2011
14th September
2011
15th September
2011
17th October
2011
23th October
2011
24th October
2011
st
1 November
2011
15th November
2011
18th November
2011
Offer sent
ent by RINA
Services
vices offer from Bethesda S.A. to
Varela Hermanos
E-mail
mail UEM/IBS/ecosur
UEM/IBS/e
america
CDM Contract
Invitation to LSC published in “La
Prensa” newspaper.
E-mail
mail confirmation from UNFCCC+
DNA
Participants list
Participants’
Contract
PDD publication on the UNFCCC webweb
page.
Emission reductions:
B.6.1. Explanation of methodological choices:
The emission reductions related to methane that would have been emitted to the atmosphere are estimated
according to the AMS-III.H (Version
Version 16). Whereas, the emission
mission reductions achieved by the energy generation
are estimated according to the AMS-I.C
AMS
(Version 19).
•
Methane recovery component (as per AMS-III.H):
AMS
Baseline Emissions
The baseline emissions from the methane recovery component are calculated as:
(1)
Where:
BEy
BE power, y
BE ww,treatment y
BE s, treatment, y
BE ww,discharge,y
BE s, final, y
Baseline emissions from the methane recovery component in year y (tCO2e)
Baseline emissions from electricity or fuel consumption in year y (tCO2e)
Baseline emissions of the wastewater treatment systems affected by the project
activity in year y (tCO2e)
Baseline emissions of the sludge treatment systems affected by the project activity in
year y (tCO2e)
Baseline methane emissions from degradable organic carbon in treated wastewater
wast
discharged into sea/river/lake in year y (tCO2e).
Baseline methane emissions from anaerobic decay of the final sludge produced in
year y (tCO2e). If the sludge is controlled combusted, disposed in a landfill with
biogas recovery, or used for soil application in the baseline scenario, this term shall
be neglected.
In determining baseline emissions using the equation above, since the historical records of one year prior to the
project implementation are not available, an ex ante measurement
nt campaign has been undertaken to determine
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the required parameters. This measurement campaign was performed upon the requirements specified in the
approved methodology and average values have been multiplied by 0.89 to account for the uncertainty range.
rang
Baseline emissions from electricity consumption (BEpower,y) are neglected since in the baseline wastewater
system there are no electric equipment/devices. Therefore:
BEpower,y= 0 tCO2e
Methane emissions from the baseline wastewater treatment systems affected by the project (BEww,treatment,y)
are determined using the COD removal efficiency if the baseline plant:
plant
(2)
Where:
Q ww, i, y
COD inflow, i, y
ηCOD,BL,i
MCF ww, treatment, BL, i
i
B o, ww
UF BL
GWP CH4
Volume of wastewater treated in baseline wastewater treatment system i in year y
(m3)
Chemical oxygen demand of the wastewater inflow to the baseline treatment system i
in year y (tonnes/m3)
COD removal efficiency of the baseline treatment system i
Methane correction factor for baseline wastewater treatment systems i (MCF = 0.8Anaerobic deep lagoon (depth more than 2 metres), as per table III.H.1)
Index for baseline wastewater treatment system
Methane producing capacity
capa
of the wastewater (IPCC value of 0.25
0.2 kg CH4/kg COD)
Model correction factor to account
account for model uncertainties (0.89)
(0.
Global Warming Potential for methane (value of 21)
As the baseline treatment system is different from the treatment system in the project scenario, the monitored
values of the COD inflow during the crediting period will be used to calculate the baseline emissions ex post.
Formulae to calculate methane
ethane emissions from the baseline sludge treatment systems affected by the project
activity are not applicable since there is no sludge treatment in the baseline. Therefore:
herefore:
BE s, treatment, y=0 tCO2e
ethane emissions from degradable organic carbon in treated wastewater discharged is
not applicable since after being treated,
treated the vinasse is used as a fertilizer in the baseline. Thus,
BE ww, discharge, y=0 tCO2e
ethane emissions from anaerobic decay of the final sludge produced is not applicable
as there is no sludge removal in the baseline scenario.
scenario Therefore:
BE s, final, y=0 tCO2e
Project Activity Emissions
Accordingg to the methodology AMS III.H (Version 16),
1 ), the project activity emissions are calculated as
follows:
(3)
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Where:
PEy
Project activity emissions in the year y (tCO2e)
PEpower,y
Emissions from electricity or fuel consumption in the year y (tCO2e).
PEww,treatment,y Methane emissions from wastewater treatment systems affected by the project activity, and
not equipped with biogas recovery, in year y (tCO2e).
PEs,treatment,y
Methane emissions from sludge treatment systems affected by the project activity, and not
equipped with biogas recovery, in year y (tCO2e).
PEww,discharge, y Methane emissions from degradable organic carbon in treated wastewater in year y (tCO2e).
PEs,final,y
Methane emissions from anaerobic decay of the final sludge produced in year y (tCO2e).
PEfugitive,y
Methane emissions from biogas release in capture systems in year y (tCO2e)
PEbiomass,y
Methane emissions from biomass stored under anaerobic conditions (tCO2e)
PEflaring,y
Methane emissions due to incomplete flaring in year y as per the
the “Tool to determine project
emissions from flaring gases containing methane”(tCO
methane”
2e)
Formulae to calculate emissions
missions from electricity or fuel consumption (PEpower,y) is not applicable since the
recovered biogas in the project scenario is used to power auxiliary
auxiliary equipment. Therefore:
PEpower,y= 0 tCO2e
Methane emissions from wastewater treatment systems affected by the project activity, and not equipped with
biogas recovery (PEww,treatment,y) are neglected, since in the project scenario, after going through
thro
the digesters,
the wastewater is conducted to an aerobic pond before being used for land application.
ethane emissions from sludge treatment systems affected by the project activity, and
not equipped with biogas recovery (PEs,treatment,y) is not applicable as in the project scenario there is no sludge
treatment. Therefore:
PEs,treatment,y=0 tCO2e
Methane emissions from degradable organic carbon in treated wastewater (PEww,discharge,y) are neglected since
in the project scenario the effluent is used for land application. Thus,
PEww,discharge,y=0 tCO2e
Methane emissions from anaerobic decay of the final sludge produced (PE
PEs,final,y) are neglected since
according to the technology supplier there is a small amount of sludge produced
ced in the biodigesters and it will
be used for soil application in aerobic conditions in the project activity. Therefore:
PEs,final,y=0 tCO2e
Methane emissions from biogas release in capture systems (PEfugitive,y ) are calculated as per the following
equation:
(4)
Where:
PE fugitive,ww ,y
Fugitive emissions through capture inefficiencies in the anaerobic wastewater treatment
systems in the year y (tCO2e)
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PE fugitive, s, y
Fugitive emissions through capture inefficiencies in the anaerobic sludge treatment
treatme systems in
the year y (tCO2e)
The equation (4) is simplified as follows as the Project does not involve methane recovery from sludge
treatment and thus PEy,fugitive,s can be neglected.
(5)
PEy,fugitive,ww is given by:
(6)
Where:
CFE ww
Capture efficiency
iency of the biogas recovery equipment in the wastewater treatment systems (a
default value of 0.9 shall be used)
MEP ww, treatment, y Methane emission potential of wastewater treatment systems equipped with biogas
recovery system in year y (tonnes)
(7)
Where:
COD removed, PJ, k, y
MCF ww, treatment, PJ, k
UF PJ
The
he chemical oxygen demand removed (difference of inflow COD and the outflow
COD) by the treatment system k of the project activity equipped with biogas
recovery in the year y (tonnes/m3)
Methane correction
correction factor for the project wastewater treatment system k equipped
with biogas recovery equipment (MCF = 0.80.8 Anaerobic reactor without methane
recovery, as per table III.H.1)
Model correction factor to account for model uncertainties (1.12)
(1.
ethane emissions from biomass stored under anaerobic conditions (PEbiomass,y) is not
applicable since no storage of biomass under anaerobic conditions takes place due to the project activity.
Therefore:
PEbiomass,y= 0 tCO2e
Methane emissions
sions due to incomplete flaring (PE
( flaring,y) are neglected since in the project scenario, the flare
will only be used in case of emergency. However, if biogas is sent to the flare system, the emissions due to
incomplete flaring shall be calculated as per the “Tool to determine project emissions from flaring gases
containing methane”. This tool involves the following seven steps:
steps
STEP 1: Determination of the mass flow rate of the residual gas that is flared
STEP 2: Determination of the mass fraction of carbon,
carbon, hydrogen, oxygen and nitrogen in the residual gas
STEP 3: Determination of the volumetric flow rate of the exhaust gas on a dry basis
STEP 4: Determination of methane mass flow rate of the exhaust gas on a dry basis
STEP 5: Determination of methane
methane mass flow rate of the residual gas on a dry basis
STEP 6: Determination of the hourly flare efficiency
STEP 7: Calculation of annual project emissions from flaring based on measured hourly values or based on
default flare efficiencies.
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The project activity
tivity involves the installation of an enclosed flare. According to the tool, for
f enclosed flares,
either of the following two options can be used to determine the flare efficiency:
(a) To use a 90% default value. Continuous monitoring of compliance with manufacturer’s
manu
specification of
flare (temperature, flow rate of residual gas at the inlet of the flare) must be performed. If in a specific
hour any of the parameters are out of the limit of manufacturer’s specifications, a 50% default value for
the flare efficiency
iciency should be used for the calculations for this specific hour.
(b) Continuous monitoring of the methane destruction efficiency of the flare (flare efficiency).
efficiency
For the purpose of determining the flare efficiency, Option (a) is adopted, and therefore, continuous
c
monitoring of compliance with manufacturer’s specifications will be performed. Moreover, according to the
tool, if option (a) is chosen, Steps 3 and 4 are not applicable.
STEP 1: Determination of the mass flow rate of the residual gas that is flared
f
This step calculates the residual gas mass flow rate in each hour h,, based on the volumetric flow rate and the
density of the residual gas. The density of the residual gas is determined based on the volumetric fraction of all
components in the gas.
(8)
Where:
FMRG,h
ρRG,n,h
FVRG,h
Mass flow rate of the residual gas in hour h (kg/h)
Density of the residual gas at normal conditions in hour h (kg/m3)
Volumetric flow rate of the residual gas in dry basis at normal conditions in the hour h (m3/h)
And:
(9)
Where:
Pn
Ru
MMRG,h
Tn
Atmospheric pressure
pre
at normal conditions (101 325 Pa)
Universal ideal gas constant (8,314 Pa.m3/kmol.K)
Molecular mass of the residual gas in hour h (kg/kmol)
Temperature at normal conditions (273.15°K)
And:
(10)
Where:
fvi,h
MMi
i
Volumetric fraction of component i in the residual gas in the hour h
Molecular mass of residual component i (kg/kmol)
The components CH4,CO, CO2, O2, H2, N2
As a simplified approach, only the volumetric fraction of methane will be measured and the difference to
100% will be considered as being nitrogen (N2).
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STEP 2. Determination of the mass fraction of carbon, hydrogen, oxygen and nitrogen in the residual gas
Determine the mass fractions of carbon, hydrogen, oxygen and nitrogen in the residual
residual gas, calculated from the
volumetric fraction of each component i in the residual gas, as follows:
(11)
Where:
fmj,h
fvi,h
AMj
MMRG,h
j
i
Mass fraction of element j in the residual gas in hour h
Volumetric fraction of component i in the residual gas in the hour h
Atomic mass of element j (kg/kmol)
Molecular mass of the residual gas in hour h (kg/kmol)
The elements carbon, hydrogen, oxygen and nitrogen
The components CH4,CO, CO2, O2, H2, N2
STEP 3. Determination of the volumetric flow rate of the
the exhaust gas on a dry basis.
basis
Not applicable.
STEP 4. Determination of methane mass flow rate in the exhaust gas on a dry basis.
basis
Not applicable.
STEP 5. Determination of methane mass flow rate in the residual gas on a dry basis.
basis
The quantity of methane
ne in the residual gas flowing into the flare is the product of the volumetric flow rate of
the residual gas (FVRG,h), the volumetric fraction of methane in the residual gas (fv
( CH4,RG,h) and the density of
methane (ρCH4,n,h) in the same reference conditions
conditions (normal conditions and dry or wet basis).
It is necessary to refer both measurements (flow rate of the residual gas and volumetric fraction of methane in
the residual gas) to the same reference condition that may be dry or wet basis. If the residual gas
ga moisture is
significant (temperature greater than 60ºC), the measured flow rate of the residual gas that is usually referred
to wet basis should be corrected to dry basis due to the fact that the measurement of methane is usually
undertaken on a dry basiss (i.e. water is removed before sample analysis).
(12)
Where:
TMRG,h
FVRG,h
fvCH4,RG,h
ρCH4,n,h
Mass flow rate of methane in the residual gas in the hour h (kg/h)
Volumetric flow rate of the residual gas in dry basis at normal conditions in the hour h (m3/h)
Volumetic
lumetic fraction of methane in the residual gas on dry basis in the hour h (NB: this
corresponds to fvi,RG,h where i refers to methane)
Density of methane at normal conditions (0.716 kg/m3)
STEP 6. Determination of the hourly flare efficiency
According to the tool, in case of enclosed flares and use of the default value for the flare efficiency, the flare
efficiency in the hour h (ηflare,h) is:
• 0% if the temperature in the exhaust gas of the flare (T
( flare) is below 500 °C for more than 20 minutes
during the hour h.
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•
•
50%, if the temperature in the exhaust gas of the flare (T
( flare) is above 500 °C for more than 40 minutes
during the hour h,, but the manufacturer’s specifications on proper operation of the flare are not met at any
point in time during the hour h.
90%, if the temperature in the exhaust gas of the flare (T
( flare) is above 500 °C for more than 40 minutes
during the hour h and the manufacturer’s specifications on proper operation of the flare are met
continuously during the hour h.
STEP 7. Calculation of annual project emissions from flaring
Project emissions from flaring are calculated as the sum of emissions from each
each hour h, based on the methane
flow rate in the residual gas (TM
TMRG,h) and the flare efficiency during each hour h (ηηflare,h), as follows:
(13
(13)
Where:
PEflare,y
TMRG,h
ηflare,h
GWPCH4
Project emissions from flaring of the residual gas stream in year y (tCO2e)
Mass flow rate of methane in the residual gas in hour h (kg/h)
Flare efficiency in hour h
Global Warming Potential of methane valid for the commitment period (tCO2e/tCH4)
Leakage Emissions
There is no leakage expected from the project activity as the technology and the equipment used is not
transferred from another activity. Therefore,
LEy=0.
Emissions Reductions
According to AMS-III.H,
III.H, emission reductions shall be estimated ex ante in the PDD using the following
equation:
(14
(14)
Where:
ER y, ex ante
LE y, ex ante
PE y, ex ante
BE y, ex ante
Ex ante emission reduction in year y (tCO2e)
Ex ante leakage emissions in year y (tCO2e)
Ex ante project emissions in year y (tCO2e)
Ex ante baseline emissions in year y (tCO2e)
For cases 1 (b), 1 (c), 1 (d) and
nd 1 (f)
(f ex post emission reductions shall be based on the lowest value of the
th
following, as per paragraph 34::
(i)
The amount of biogas recovered and fuelled or flared (MDy)
(
) during the crediting period, that is
monitored ex post;;
(ii)
Ex post calculated baseline, project
project and leakage emissions based on actual monitored data for the
project activity.
For cases 1 (b), 1 (c), 1 (d)
d) and 1 (f): it
it is possible that the project activity involves wastewater and sludge
treatment systems with higher methane conversion factors (MCF) or with higher efficiency than the treatment
systems used in the baseline situation. Therefore the emission reductions achieved by the project activity is
limited to the ex post calculated baseline emissions minus project emissions using the actual monitored data for
the project activity. The emission reductions achieved in any year are the lowest value of the following:
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ER y, ex post = min ((BE
BE y, ex post- PE y ex post- LE y, ex post), (MDy- PE y ex post- LE y, ex post))
(15)
Where:
(16)
Where:
BGburnt,y
wCH4, y
D CH4
FE
•
Biogas flared/combusted in year y (m3)
Methane content in the biogas in the year y (volume fraction)7
Density of methane at the temperature and pressure of the biogas in the year y (tonnes/m3)
Flare efficiency in year y (fraction). If the biogas is combusted for gainful purposes,
purposes e.g. fed
to an engine, an efficiency of 100% may be applied.
Energyy generation component (as per AMS-I.C):
AMS
Baseline Emissions
The baseline emissions as discussed in Section B.4 will include emissions thatt would have occurred in the
absence of the project activity. According to the approved AMS I.C methodology, paragraphs 21 and 22 are
used to calculate the baseline emissions; corresponding equations are given below.
Baseline emissions for heat production
productio
Since in the baseline situation steam would have been generated in a bunker-based
bunker
boiler, the following
equation of the methodology AMS-I.C
AMS
is applied:
(17)
Where:
(16)
BE thermal, CO2,y Baseline emissions from steam/heat displaced by the project activity
ac
during the year
y; tCO2e
EG thermal,y
The net quantity of steam/heat supplied by the project activity during the year y; TJ
EF FF,CO2
The CO2 emission factor of the fossil fuel that would have been used in the baseline
plant (IPCC default
defau emission factor);tCO2/TJ
The efficiency of the plant using fossil fuel in the absences of the project activity.
Baseline emissions for electricity production
According to AMS-IC,
IC, baseline emissions for supply of electricity to and/or displacement of electricity from
fro a
grid shall be calculated as per the procedures detailed in AMS-I.D.
AMS
or AMS-I.F
I.F as applicable.
Version 17 of the AMS-I.D
I.D is applicable since the project displaces energy form the national grid. Thus, the
following equation is applied:
(18)
Where:
BEy
7
Baseline Emissions in year y (tCO
(
2)
Biogas volume and methane content measurements shall be on the same basis (wet or dry).
31
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EGBL, y
EFCO2, y
Quantity of net electricity supplied to the grid as a result of the implementation of the CDM
project activity in year y (MWh)
Emission Factor of the grid in year y (tCO2/MWh)
The Emission Factor is calculated as a combined margin (CM), consisting of the combination of the operating
margin (OM) and build margin (BM), according to the procedures prescribed in the “Tool to calculate the
Emission Factor for an electricity system”.(Please
system”
refer to Annex 3 for detailed information).
Total baseline emissions are calculated as follows:
(19)
Where:
BE thermal,y
Baseline emissions from electricity and steam displaced by the project activity during the year
y (tCO2e).
Baseline emissions from steam/heat production
product
(tCO2e).
Baseline emissions for displacement of fossil fuel used for electricity generation in the
Panamenian grid (tCO2e).
Project Emissions
According to AMS-I.C, project emissions include:
- CO2 emissions from on-site
on
consumption
mption of fossil fuels due to the project activity shall be calculated
using the latest version of the .Tool to calculate project or leakage CO2 emissions from fossil fuel
combustion.;
using the latest version of the Tool
- CO2 emissions from electricity consumption by the project activity using
to calculate baseline, project and/or leakage emissions from electricity consumption;
consumption
- Any other significant emissions associated with project activity within the project boundary;
- For geothermal project activities, project participants shall account for the following emission sources,
where applicable: fugitive emissions of carbon dioxide and methane due to release of nonnon
condensable gases from produced steam; and carbon dioxide emissions resulting from combustion of
fossil fuels related to the operation of the geothermal power plant.
Since the project activity does not involve on-site
on e consumption of fossil fuel nor electricity consumption other
than the one produced withh the recovered biogas. And, there no other significant
significant emissions associated with the
project activity, thus:
PEy= 0 tCO2e
Leakage Emissions
According to paragraphs 47 and 48 of the AMS-I.C
AMS I.C methodology there is no leakage expected from the project
activity as energy generating equipment is not transferred
transferred from outside the boundary and also the project
activity does not involve any collection/processing/transportation of biomass residues. Therefore,
LEy=0.
Emission reductions are calculated as follows:
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ERy = BEy − PEy − LEy (20)
Where:
ERy
BEy
PEy
LEy
Emission reductions in year y (tCO2e/y).
Baseline Emissions in year y (tCO2e/y).
Project emissions in year y (tCO2e/y).
Leakage emissions in year y (tCO2e/y).
Since PEy and LEy= 0 tCO2e,, equation (20) can be simplified as follows:
ERy = BEy (21)
B.6.2. Data and parameters that are available at validation:
Data / Parameter:
Data unit:
Description:
Source of data used:
Value applied:
Justification of the
choice of data or
description of
measurement methods
and procedures actually
applied :
Any comment:
Depth of open lagoon
m
Depth of open lagoon from the water surface to the bottom.
Plant condition
Over 3.0 m (Please refer to Table 2 for detailed information).
Data / Parameter:
Data unit:
Description:
MCFwww,treatment,BL,i
No unit
Methane correction factor for the wastewater treatment system that will be
equipped with methane recovery and combustion.
combust
IPCC default value for anaerobic decay of the untreated wastewater
0.8
When the depth of anaerobic open
open lagoons is more than 2 meters, then the MCF in
table III.H.1 is used.
Value applied:
choice of data or
description of
measurement methods
applied :
Any comment:
Data / Parameter:
Data unit:
Description:
Value applied:
choice of data or
description of
Essential to determine
determi if methane emissions occur into the lagoon in the baseline.
This data is essential to determine the methane emission potential of the wastewater
entering the digesters.
digester Used to calculate baseline emissions.
MCF
CFww, discharge, BL
No unit
Methane correction factor based on discharge pathway in the baseline situation of
the wastewater
0.0
Inn the baseline system after being treated the effluent is used as a fertilizer in the
nearby plantations.
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measurement methods
applied :
Any comment:
Data / Parameter:
Data unit:
Description:
Value applied:
choice of data or
description of
measurement methods
applied :
Any comment:
Data / Parameter:
Data unit:
Description:
Value applied:
choice of data or
description of
measurement methods
applied :
Any comment:
Data / Parameter:
Data unit:
Description:
Value applied:
choice of data or
description of
measurement methods
applied :
Any comment:
Data / Parameter:
Data unit:
MCF ww,final, PJ,k
No unit
Methane correction factor based on type of treatment and discharge pathway of the
wastewater, fraction
0.0
Based on the type
type of wastewater treatment and discharge pathway: Aerobic
treatment, well managed,
managed as per table III.H.I.
In project scenario, after going through the digesters, the
the wastewater is conducted to
two aerobic ponds before being used for land application.
MCFww,PJ,disharge,k
No unit.
Methane correction factor based on discharge
discharge pathway in the baseline situation of
the wastewater
0.0
In the project scenario, the effluent is irrigated in the nearby plantations.
-
MCFww,treatment,PJ,k
No unit
Methane correction factor based on type of treatment and discharge
discha
pathway of the
wastewater, fraction
0.8
Based on the type
type of wastewater treatment and discharge pathway: Anaerobic
reactor without methane recovery,
recovery as per table III.H.I.
Used for project emissions calculation.
Bo,ww
tCH4/tCOD
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Description:
Value applied:
choice of data or
description of
measurement methods
applied :
Any comment:
Methane producing capacity of the wastewater
Methan
IPCC default value for industrial wastewater
0.25
IPCC value for wastewater
waste
of 0.25 kgCH4/kg COD.
-
Data / Parameter:
Data unit:
Description:
Value applied:
choice of data or
description of
measurement methods
applied :
Any comment:
ηCOD,BL,i
%
COD
OD removal
r
efficiency of the baseline treatment system
tem i
Calculated as per measurement campaign
88.74
74
-
Data / Parameter:
Data unit:
Description:
CFEww
No unit/
Capture efficiency of the
the biogas recovery equipment in the wastewater treatment
systems
AMS
AMS-III.H
0.9
-
Value applied:
choice of data or
description of
measurement methods
applied :
Any comment:
Data / Parameter:
Data unit:
Description:
Value applied:
choice of data or
description of
measurement methods
applied :
Determined as per paragraph 27 of AMS-III.H
AMS III.H (Version 16)
-
MMCH4
kg/kmol
Molecular mass of methane
As per Table 1 of the “Tool to determine project emissions from flaring gases
containing methane”
16.04
-
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Any comment:
-
Data / Parameter:
Data unit:
Description:
Value applied:
choice of data or
description of
measurement methods
applied :
Any comment:
ρCH4,n
kg/m3
Density of methane at normal conditions
UNFCCC
UNFCCC-constant
value
0.716
Thee value is adopted from Table 1. Constants used in equations as published in the
Methodological “Tool to determine project emissions from flaring gases containing
methane”.
-
Data / Parameter:
Data unit:
Description:
Value applied:
choice of data or
description of
measurement methods
applied :
Any comment:
GWPCH4
No unit
Globa Warming Potential for methane
Global
AMS
AMS-III.H
21
-
Data / Parameter:
Data unit:
Description:
MMN2
kg/kmol
Molecular mass of nitrogen
28.02
-
Value applied:
choice of data or
description of
measurement methods
applied :
Any comment:
Data / Parameter:
Data unit:
Description:
Value applied:
-
AMn
kg/kmol (g/mol)
Atomic mass of nitrogen
14.01
-
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choice of data or
description of
measurement methods
applied :
Any comment:
Data / Parameter:
Data unit:
Description:
Value applied:
choice of data or
description of
measurement methods
applied :
Any comment:
Data / Parameter:
Data unit:
Description:
Value applied:
choice of data or
description of
measurement methods
applied :
Any comment:
Data / Parameter:
Data unit:
Description:
Value applied:
choice of data or
description of
measurement methods
applied :
Any comment:
Pn
Pa
Atmospheric pressure at normal conditions
101 325
-
Ru
Pa.m3/kmol.K
Universal ideal gas constant
8 314.472
containing methane
-
Tn
K
Temperature at normal conditions
containing methane
273.15
-
-
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Data / Parameter:
Data unit:
Description:
Value applied:
choice of data or
description of
measurement methods
applied :
Any comment:
Data / Parameter:
Data unit:
Description:
Value applied:
choice of data or
description of
measurement methods
applied :
Any comment:
Data / Parameter:
Data unit:
Description:
Value applied:
choice of data or
description of
measurement methods
applied :
Any comment:
Data / Parameter:
Data unit:
Description:
Value applied:
choice of data or
MVn
m3/kmol
/k
Volume of one mole of any ideal gas at normal
containing methane
22.414
-
NAi,j
Dimensionless
Number of atoms of element j in component i,
As per Table 1 of the “Tool to determine project
ect emissions from flaring gases
containing methane
Depending on molecular structure
-
Q steam, boiler
TPH
Quantity of steam generated
gene
by bunker based boiler
Manufacturer data
9.315 (20,700 lb/h )
-
P steam, boiler
bar
Pressure generated by bunker based boiler
Manufacturer data
11 (153 psi)
-
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description of
measurement methods
applied :
Any comment:
Data / Parameter:
Data unit:
Description:
Value applied:
choice of data or
description of
measurement methods
applied :
Any comment:
Data / Parameter:
Data unit:
Description:
Value applied:
choice of data or
description of
measurement methods
applied :
Any comment:
Data / Parameter:
Data unit:
Description:
Value applied:
choice of data or
description of
measurement methods
applied :
Any comment:
T boiler
°C
Steam temperature generated by bunker based boiler
Manufacturer data
182
182.22(360°F)
-
ȃ boiler
%
Efficiency of the boiler using fossil fuel that would have been used in the absence
of the project activity
Calculated
%
84%
This value has been used to calculate the baseline emission from heat production.
EFCO2
tCO2/TJ
CO2 emission factor per unit of energy of the bunker
nker that would have been used in
the baseline plant and in the project emissions calculation
IPCC (Volume 2, Chapter 1, Table 1.4)
75.5 (lower
(
value )
IPCC value has been chosen for conservative estimation and because no local or
regional data is available.
-
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Data / Parameter:
Data unit:
Description:
EFCO2
tCO2/MWh
Grid Emission Factor
Calculated value as per “Tool to calculate the emission factor for an electricity
system” (Version 02)
0.6699
699 (average of 3 years 2007, 2008 and 2009) (Please refer to Annex 3 for
detailed information)
The project activity involves displacement of grid electricity. As per the “Tool to
calculate the emission factor for an electricity system” (Version 02.2.1), the EF of
the
he Panamanian grid is calculated based on the weighted average of the emissions
of the current generation mix in tCO2/MWh. The data used is the most recently
available at the time of the PDD preparation.
Value applied:
choice of data or
description of
measurement methods
applied :
Any comment:
B.6.3
Value is calculated ex-ante
ex
and is fixed
xed during the first crediting period.
Ex-ante
ante calculation of emission reductions:
Emission Reductions associated with the methane recovery component (as per AMS-III.H):
AMS
Baseline Emissions
treatment systems affected by the project
a) Methane emissions from the baseline wastewater treatment
(BEww,treatment,y) are calculated below:
Parameter
Value
Description
Source
Volume of wastewater treated in baseline
wastewater treatment system i in year y (m3)
Distillery
design
specifications
(2)
Q ww, i, 2013
=
1
110,814
COD inflow, i, 2013
=
0
0.0584
88.7%
ηCOD,BL,i
MCF ww, treatment, BL, i
=
0.8
B o, ww
=
0.25
UF BL
=
0.89
GWP CH4
=
21
Chemical oxygen demand of the wastewater
inflow to the baseline treatment system i in year
y (tonnes/m3)
COD removal efficiency of the baseline
treatment system i
Methane correction factor for baseline
wastewater treatment systems i
Model correction factor to account for model
uncertainties
Measurement
campaign
Calculated
MCF values as per
table III.H.1
IPCC value of 0.25
kg CH4/kg COD
AMS-III.H
AMS-III.H
BEww,treatment, 2013= 110,814m3/y*0.0584 tonnes/m3*88.7%*0.8*0.25 CH4/kg COD*0.89*21=
BEww,treatment, 2012= 24,009 tCO2e/y
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BEww,treatment,y forecast for 20112-2018 is presented below:
BEwww,treatment,y (tCO2/y)
2013
201
2014
2015
2016
20117
24,009
25,602
25,602
25,602
25,602
Table 9: BEww,treatment,y forecast for 2013-2019.
2018
25,602
2019
25,602
Baseline emissions (BEy) are:
Parameter
(1)
Value
Source
BEy =(BE
=( power, y +BE ww,treatment y +BE s, treatment, y +BE ww,discharge,y+ BE s, final, y)
BE power, 2013
=
0
BE ww,treatment 2013
=
24,009
BE s, treatment, 2013
=
0
BE ww,discharge,2013
=
0
BE s, final, 2013
Description
=
0
Baseline emissions from electricity or fuel
consumption in year y (tCO2e)
Baseline emissions of the wastewater treatment
systems affected by the project activity in year y
(tCO2e)
Baseline emissions of the sludge treatment
systems affected
ed by the project activity in year y
(tCO2e)
Baseline methane emissions from degradable
organic carbon in treated wastewater discharged
into sea/river/lake in year y (tCO2e).
Baseline methane emissions from anaerobic
decay of the final sludge produced in year y
(tCO2e). If the sludge is controlled combusted,
disposed in a landfill with biogas recovery, or
used for soil application in the baseline scenario,
this term shall be neglected.
As per Section
B.6.1
Calculated from
equation (2)
As per
B.6.1
Section
As per
B.6.1
Section
As per
B.6.1
Section
BE2013 = 24,009 tCO2e/y
BEy forecast for 2013-2019 is presented below:
BEy (tCO2/y)
2013
2014
2015
2016
2017
24,009 25,602
25,602
25,602 25,602
Table 10: BEy forecast for 2013-2019
2018
25,602
2019
25,602
Project Activity Emissions
Methane emissions from biogas release in capture systems (PEfugitive,y ) are calculated as per the following
equation:
(4)
Where:
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PE fugitive,ww ,y
PE fugitive, s, y
Fugitive emissions through capture inefficiencies in the anaerobic wastewater treatment
systems in the year y (tCO2e)
Fugitive emissions through capture inefficiencies in the anaerobic sludge treatment systems in
the year y (tCO2e)
The equation (4)) is simplified as follows as the Project does
does not involve methane recovery from sludge
treatment and thus PEy,fugitive,s are not relevant to the project.
(5)
PEy,fugitive,ww is given by:
(6)
Where MEP ww, treatment, y is calculated as follows:
Parameter
Value
Description
Source
(7)
Q ww, i, 2013
=
1
110,814
Volume of treated wastewater discharged in year
y (m3)
The
he chemical oxygen demand removed
(difference of inflow COD and the outflow
COD) by the treatment system k of the project
activity equipped with biogas recovery in the
year y (tonnes/m3)
Methane correction factor based on discharge
pathway in the baseline situation of the
wastewater (fraction).
Distillery design
specifications
UEM Group
estimations
COD removed, PJ, k, 2013
=
0.0
0.03799
MCFww, treatment, PJ, k
=
0.8
B o, ww
=
0.25
IPCC value of 0.25
kg CH4/kg COD
UF PJ
=
1.12
Model correction factor to account for model
uncertainties
AMS-III.H
MCF values as per
table III.H.1
MEP ww, treatment, 2013= 110,814
8140 m3/y*0.25 kg CH4/kg COD*1.12* 0.03799 tonnes/m3*0.8= 1,054tonnes
Consequently:
Parameter
Value
Description
(6)
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CFE ww
=
0.9
MEP ww, treatment, 2013
=
1,054
GWP CH4
=
21
Capture efficiency of the biogas recovery
equipment in the wastewater treatment systems
Methane emission potential of wastewater
treatment systems equipped with biogas
recovery system in year y (tonnes)
AMS-III.H
Calculated from
equation (7)
AMS-III.H
PEfugitive,ww,2013
fugitive,ww,201 = (1-0.9)*1,054 tonnes*21= 2,213tCO
tCO2e/y
PEfugitive,ww,y forecast for 2013--2019 is presented in the following table:
PEfugitive,ww,y
(tCO2/y)
2013
2014
2015
2016
2017
2018
2019
2,213
2,360
2,360
2,360
2,360
2,360
2,360
Table 11: PEfugitive,ww,y forecast for 2013-2019
The project activity emissions from the Systems affected by the project activity are:
Parameter
(3)
PE power, 2013
Value
Description
PEy =(PE
=(
power, y +PE ww,treatment y+PE
PEfugitive, y+ PE biomass, y+ PEflaring, y)
=
0
PEww,treatment,2013
=
0
PE s, treatment, 2013
=
0
PE ww,discharge,2013
=
0
PE s, final, 2013
=
0
PEfugitive,2013
=
2,213
PEbiomass,2013
=
0
PEflaring,2013
=
0
s, treatment, y
Source
+
+PE
ww,discharge,y+
Emissions from electricity or fuel consumption
in the year y (tCO2e)
Methane emissions from wastewater treatment
systems affected by the project activity, and not
equipped
ipped with biogas recovery, in year y
(tCO2e).
Methane emissions from sludge treatment
systems affected by the project activity, and not
equipped with biogas recovery, in year y
(tCO2e).
Methane emissions from degradable organic
carbon in treated wastewater in year y (tCO2e)
Methane emissions from anaerobic decay of the
final sludge produced in year y (tCO2e).
Methane emissions from biogas release in
capture systems in year y (tCO2e)
Methane emissions from biomass stored under
anaerobic conditions (tCO2e)
Methane emissions due to incomplete flaring in
year y as per the “Tool to determine project
emissions from flaring gases containing
methane” (tCO2e)
PE2013 = 2,213 tCO2e/y
43
PE
s, final, y+
As per Section
B.6.1
As per Section
B.6.1
As per Section
B.6.1
As per Section
B.6.1
As per Section
B.6.1
Calculated as per
equation (6)
As per Section
B.6.1
As per Section
B.6.1
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PEy forecast for 2013-2019 is:
PEy (tCO2/y)
2013
2014
2015
2016
2017
2,213
2,360
2,360
2,360
2,360
Table 12: PEy forecast for 2013-2019
2018
2,360
2019
2,360
Leakage Emissions
LEy=0.
(14)
ER 2012, ex ante= 24,009 - (2,213- 0) = 21,796 tCO2e/y
The ex ante emission reductions associated with the methane recovery component for the first crediting period
is presented in the following table:
2013
2014
2015
2016
2017
2018
Estimation of emission
reductions (tCO2e)
21,796
23,242
23,242
23,242
23,242
23,242
2019
23,242
Total (tonnes of CO2e)
161,248
Year
Table 13:: Emission reductions associated with methane recovery - 1st crediting period
Emission Reductions associated with the electricity generation component (as per AMS-I.C):
A
According to Section B.6.1, baseline emission related to heat production can be estimated as follows:
(17)
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Net quantity of steam/heat supplied by the project activity (EG thermal, y)
Steam
consumption8
Steam
enthalpy
EG
thermal,y
Tons
MJ/t
TJ
2013
2014
2015
2016
2017
2018
2019
15,094
15,094
15,094
15,094
15,094
15,094
15,094
2,436
36.
36.8
2,436
36
36.8
2,436
36.
36.8
2,436
36.
36.8
2,436
36.
36.8
2,436
36.
36.8
2,436
36.
36.8
TOTAL
257.4
Table 14:: Net quantity of thermal energy
energy supplied by the project activity
As per equation (17),.. baseline emissions are calculated by multiplying the emission factor of the fossil used in
the baseline by the total steam/heat energy produced in the project activity and divided by the baseline boiler’s
efficiency.
The bunker C EF is 75.5 tCO2/TJ9
Baseline emissions for heat production are shown below:
EF Bunker
η BL,thermal
tCO2
tCO2/TJ
2013
2014
2015
2016
2017
2018
2019
BE thermal,CO2, y
75.5
75.5
75.5
75.5
75.5
75.5
75.5
84%
3,306
306
84%
3,306
306
84%
3,306
306
84%
3,306
306
84%
3,306
306
84%
3,306
306
84%
3,306
306
TOTAL
23,139
Table 15:: Baseline emissions related to heat productiont (BEthermal,CO2,y)
8
Based on estimations on the increase of alcohol
alco
production.
9
IPCC default values (Volume 2, Chapter 1, Table 1.3)
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Baseline emissions due to electricity generation from biogas
EGy has been estimated as the total electricity generated by the used of biogas.
As the grid Emission Factor is:: 0.6699 tCO2/MWh, the
he emission reductions from the electricity generated are:
2013
2014
2015
2016
2017
2018
2019
Energy
generated
from
biogas10
MWh
EF grid
BEy,EG
tCO2/MWh
tCO2
10,435
10,435
10,435
10,435
10,435
10,435
10,435
0.6699
0.6699
0.6699
0.6699
0.6699
0.6699
0.6699
6,991
6,991
6,991
6,991
6,
6,991
6,991
6,991
TOTAL
48
48,934
Table 16: Baseline emissions for electricity produced from biogas (BEy,EG).
According to equation (19), the total baseline emissions are calculated as follows:
follows:
2013
2014
2015
2016
2017
2018
2019
019
BE thermal, y
BE electricity,y
tCO2
tCO2
Total
otal
Baseline
aseline
Emissions
missions
Energy
component
tCO2
3,306
3,306
3,306
3,306
3,306
3,306
3,306
6,991
6,991
6,991
6,991
6,991
6,991
6,991
10,296
10,296
10,296
10,296
10,296
10,296
10,296
72,073
073
TOTAL
23,139
48,934
Table 17: Baseline emissions-Energy
Energy generation component
10
As per estimations from UEM Group (technology provider)
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Project Emissions
PEy= 0 tCO2e
Leakage Emissions
LEy=0.
Since PEy and LEy= 0 tCO2e:
ERy = BEy (21)
The forecast emission reductions associated with the energy generation component for the first crediting period
is presented in the following table:
Year
Energy Generation Estimation of
emission reductions (tCO2e)
2013
2014
2014
2015
2016
2017
2018
10,296
10,296
10,296
10,296
10,296
10,296
10,296
2019
72,073
Table 18: Emission reductions associated with energy
e
generation - 1st crediting period
B.6.4
Summary of the ex-ante
ex
estimation
on of emission reductions:
Year
Estimation
of project
activity
emissions
(tCO2e)
Estimation
of baseline
emissions
(tCO2e)
Estimation
of leakage
(tCO2e)
Estimation
of emission
reductions
(tCO2e)
2013
2014
2015
2016
2017
2,213
2,360
2,360
2,360
2,360
34,305
35,898
35,898
35,898
35,898
0
0
0
0
0
32,092
33,538
33,538
33,538
33,538
2018
2,360
35,898
0
33,538
2019
2,360
35,898
33,538
16,372
249,693
0
0
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B.7
Application of a monitoring methodology and description of the monitoring plan:
B.7.1
Data and parameters monitored:
All monitored data needed for verification will be kept for two years, at least, after the end of the crediting
period or the last issuance of CERs.
Data / Parameter:
Data unit:
Description:
Source of data to be
used:
Value of data:
Description of
measurement methods
and procedures to be
applied:
QA/QC procedures to
be applied:
Any comment:
Data / Parameter:
Data unit:
Description:
used:
Value of data
Continuous operation of the equipment/system
e
On--site checking.
Annual check of all appliances or a representative sample thereof to ensure that
tha they
are still operating or are replaced by an equivalent in service appliance
As per the existing data management system.
-
Qww,j,y
m3/month
Flow of wastewater
Distillery design specifications
As per Table 11:
2011
2012
2013
2014
2015
2016
2017
2018
2019
Description of
measurement methods
applied:
QA/QC procedures to
be applied:
Any comment:
Vinasse
(m3/year)
110,814
116,765
123,849
132,066
132,066
132,066
132,066
132,066
132,066
Monitored continuously with a flow meter to be installed upstream of the digesters.
The flow meter will undergo maintenance/calibration
maintenance/calibration in accordance with the
manufacturer’s specifications.
-
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Data / Parameter:
Data unit:
Description:
used:
Value of data
Description of
measurement methods
applied:
QA/QC procedures to
be applied:
Any comment:
Data / Parameter:
Data unit:
Description:
used:
Value of data
Description of
measurement methods
applied:
QA/QC procedures to
be applied:
Any comment:
CODinflow,i,y
tonnes/m3
Chemical oxygen demand removed by project wastewater treatment system k of the
project activity equipped with
wit biogas recovery in year y (tonnes/m3), calculated as the
difference between inflow COD and the outflow COD in system k.
Directly measured by Varela Hermanos.
0.0584
584
Samples and measurements will ensure a 90/10 confidence/precision level. The
results will be monthly recorded.
Sampling and analysis will be carried out according to internationally recognized
procedur COD will be measured though representative sampling
procedures.COD
-
CODremoved,PJ,k,y
tonnes/m3
Chemical oxygen demand removed by project wastewater treatment system k of the
project activity equipped with biogas
b
recovery in year y (tonnes/m3), calculated as the
difference between inflow COD and the outflow COD in system k.
Directly measured by Varela Hermanos.
0.0379
379
Calculated based on samples that will be taken upstream and downstream the
digester. Samples and measurements will ensure a 90/10 confidence/precision level.
level
The results will be monthly recorded.
Sampling and analysis will be carried out according to internationally recognized
procedures.COD will be measured though representative sampling
procedures.COD
-
Data / Parameter:
Data unit:
Description:
used:
Value of data
Description of
measurement methods
applied:
QA/QC procedures to
be applied:
Any comment:
-
Data / Parameter:
Data unit:
Description:
FVRG
Nm
m3 biogas/year
Amount of biogas recovered at normal conditions
Sfinal,PJ,y
tonnes/year
Amount of sludge generated by the
th project activity
On--site measurement
0
The end-use
end use of the final sludge will be monitored during the crediting period.
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used:
Value of data
Description of
measurement methods
applied:
QA/QC procedures to
be applied:
Any comment.
N/A -this parameter is not relevant for the purpose of the ex-ante calculation
Monitored continuously using a normalized flow meter. Results will be monthly
recorded on a record sheet.
Flow meter will be periodically
periodically calibrated according to the manufacturer’s
recommendations.
-
Data / Parameter:
Data unit:
Description:
used:
Value of data
Description of
measurement methods
applied:
QA/QC procedures to
be applied:
Any comment:
FVFL
Nm
m3biogas/year
Surplus biogas sent to flare system
Data / Parameter:
Data unit:
Description:
used:
Value of data
Description of
measurement methods
applied:
QA/QC procedures to
be applied:
Any comment:
fvCH4,RG
Fraction
Volumetric fraction of CH4 in the residual gas in the hour h.
Data / Parameter:
Data unit:
Description:
used:
Value of data
Description of
measurement methods
applied:
Tflare
°Celsius
Celsius
Temperature in the exhaust gas of the flare.
N/A -this
his parameter is not relevant for the purpose of the ex-ante calculation
Measured continuously by flow meters. Results will be monthly recorded on a record
sheet.
Flow meters will undergo maintenance/calibration according to the manufacturer’s
recommendations.
-
N/A- as it is not relevant for the purpose of ex ante calculations
N/A
Measured with a continuous analyser that can directly measure methane
methan content in
the biogas.
biogas Results will be monthly recorded on a record sheet.
The gas analyser will undergo maintenance/calibration subject to appropriate
industry standards.
The methane content measurement will
will be carried out close to the location where the
biogas flow measurement takes place.
N/A- this parameter is not relevant for the purpose of the ex-ante estimation.
N/A
Continuously measured and hourly recorded on a record sheet.
sheet
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QA/QC procedures to
be applied:
Any comment:
The thermocouples
t
will be replaced or calibrated every year.
year
-
Data / Parameter:
Data unit:
Description:
used:
Value of data:
Description of
measurement methods
applied:
QA/QC procedures to
be applied:
Any comment:
Q,steam,p,y
Tonnes/year
Quantity of steam supplied by the project activity during the year y
Data / Parameter:
Data unit:
Description:
used:
Value of data:
Description of
measurement methods
applied:
QA/QC procedures to
be applied:
Any comment:
Psteam, boiler
bar
Pressure of steam extracted from the boiler
15,094
Continuously measured, integrated hourly and at least monthly recorded on a record
sheet.
This parameter is measured at the outlet of the boiler.
11
Continuously measured, integrated hourly and at least monthly recorded on a record
sheet.
This parameter is measured
meas
at the outlet of the boiler.
This parameter is required to determine enthalpy of the steam.
Data / Parameter:
Data unit:
Description:
used:
Value of data:
Description of
measurement methods
applied:
QA/QC procedures to
be applied:
Any comment:
T steam, boiler,
°C
Temperature of steam extracted from the boiler
Data / Parameter:
Data unit:
T feedwater,
°C
182.22
Continuously measured and at least monthly recorded on a record sheet.
Thiss parameter is measured at the outlet of the boiler.
This parameter is required to determine enthalpy of the steam.
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Description:
used:
Value of data:
Description of
measurement methods
applied:
QA/QC procedures to
be applied:
Any comment:
Temperature of feedwater
82
Continuously measured and at least monthly recorded on a record sheet.
This parameter
parameter is required to determine enthalpy of the steam.
Data / Parameter:
Data unit:
Description:
EGthermal,y
TJ/year
used:
Value of data:
Description of
measurement methods
applied:
Net quantity of thermal energy supplied by the project activity during the year y.
36.8
The following calculation will be made at least once a year.
- The feed-water
water temperature will be used to determine the feed-water
feed
enthalpy
using standard steam table.
- The steam pressure and the steam temperature will be used to determine the
steam enthalpy using standard steam table.
- The amount of feed-water
water will be multiplied by the feed-water
feed
enthalpy to
calculate the amount of energy containing in the feed-water.
feed
- The amount of steam produced will be multiplied by the steam enthalpy to
calculate the amount of steam energy produced.
Net quantity of steam supplied by the project activity = the amount
a
of steam energy
produced minus the amount of energy containing in the feed-water.
feed
QA/QC procedures to
be applied:
Any comment:
Data / Parameter:
Data unit:
Description:
used:
Value of data
Description of
measurement methods
applied:
QA/QC procedures to
be applied:
Any comment:
-
EG BL,y
MWh/year
Quantity of net electricity produced with the biogas in year y
On--site measurements.
10,435
Monitored continuously using electricity meters. (Hourly measurement and monthly
recording).
Electricity meters will
will undergo maintenance/calibration in accordance with
appropriate industry standards.
-
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B.7.2
Description of the monitoring plan:
The project is operated and managed by Varela Hermanos which ensures the overall site operation safety in
accordance
ccordance with Panamanian Laws and technology providers’ guidelines.
Eng. José Javier Dopeso, Director of Operations of Varela Hermanos, will establish a CDM team dedicated to
the project
roject activity monitoring. The Board of Directors of Varela Hermanos willl appoint a CDM coordinator
later on.
The responsibility of the CDM coordinator will cover the following items:
1. Monitoring equipment compliance checks,
check , ensuring that instrumentations and devices are available
and properly suited to perform their functions for emission reduction monitoring;
2. Development, execution, analysis and improvement of the Standard (CDM) Monitoring/Reporting
Procedures;
3. Deployment of the procedures through trainings, ensuring that these procedures are fully complied
with;
4. Communicationn and coordination between and among multiple departments in the company and at
group levels to disseminate CDM related information;
5. Check the calculation of the emission reductions ;
6. Reporting of the emissions reductions calculation ;
7. Liaison with a DOE during the verification.
For more detailed information on the data and parameters monitored,
monitored, please refer to Section B.7.1.
It is worth mentioning that all monitored parameters will be stored for a period of 2 years after the end of the
crediting period.
B.8
Date of completion of the application of the baseline and monitoring methodology and the
name of the responsible person(s)/entity(ies)
Date of completion: 14/11/2011
Name of entity determining the baseline:
ecosur america S.A.
Cabrera 6009 -1414 Buenos Aires,
Argentina
Tel. +54 11 4776 4406
Fax +54 11 6379 1992
ecosur america is not a project participant but the CDM consultant.
Contact information of the persons responsible for the baseline calculation and the monitoring plan
elaboration:
MSc. Eng.. María Belén MIGONE
[email protected]
america.com
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SECTION C. Duration of the project activity / crediting period
C.1
activity
Duration of the project activity:
C.1.1. Starting date of the project activity:
activity
According to the “Glossary of CDM terms”, the
the starting date of a CDM project activity is the earliest date at
which either the implementation or construction or real action of a project activity begins. The project has not
been implemented nor constructed
constructe yet. Only a pre-feasibility
feasibility study has been undertaken. Thus, there is no
starting date of the project.
C.1.2. Expected operational lifetime of the project activity:
20 years.
C.2
Choice of the crediting period and related information:
wable crediting period
C.2.1. Renewable
C.2.1.1.
Starting date of the first crediting period:
The crediting period starts upon the effective date of registration of the CDM project activity,
activity which is
expected to be on 10/10/2012, or the commissioning of the wastewater treatment plant, whichever comes later.
C.2.1.2.
Length of the first crediting period:
7 years
C.2.2. Fixed crediting period:
period
C.2.2.1.
Starting date:
C.2.2.2.
Length:
N/A
N/A
SECTION D. Environmental impacts
>>
D.1.
If required by the host Party,
Par documentation on the analysis of the environmental impacts
of the project activity:
The project activity requires presenting an Environmental Impact Assessment to ANAM (Ministry of
Environment) category I – the simplest one. This assessment (EIA) is presently being conducted by local
environmental consultants and should be presented to local authorities in a few weeks.
weeks
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D.2.
If environmental impacts are considered significant by the project participants or the host
Party, please provide conclusions
clusions and all references to support documentation of an environmental
impact assessment undertaken in accordance with the procedures as required by the host Party:
Noo negative environmental impacts are expected due to the implementation of the project activity.
SECTION E. Stakeholders’ comments
E.1.
Brief description how comments by local stakeholders have been invited and compiled:
A meeting with the local stakeholders was conducted on November 1st, 2011 at the Municipal Palace of Pesé.
Stakeholders
rs were invited to attend the meeting via letter,
letter, phone calls and emails.
emails The invitation letters were
sent to people that could have interest, be affected by or have issues in relation to the project (local leaders,
government civil servants and state officials,
offi
local industries and the media).
In addition, a newspaper article was published on October 23rd in “La
La Prensa”,
Prensa the main national daily
newspaper,, declaring the date, time, venue and topic of the meeting.
meeting Also, several announcements posters were
placed in the surroundings of the distillery and the Municipality of Pesé.. The following pictures show the
location of some of these posters.
Figure 7:: Pictures showing locations of the posters announcing the meeting
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The meeting started at 1.30 pm.
pm All guests were registered and received a non-technical
non
summary of the
project (in Spanish) before the meeting.
meeting Afterwards, Eng. José J. Dopeso, Director of Operations of Varela
Hermanos, gave a welcome speech and presented the project and its benefits including the reduced
environmental impacts. Mr. Timothée Lazaroo, managing partner of ecosur america,
america introduced the CDM and
explained how the project is going to reduce GHG emissions.
emissions
Figure 8:: Scenes from the Local Stakeholder Consultation Meeting
After all the aspects of the project were presented to the participants, they were discussed by the stakeholders
and some of them asked questions about the CDM.
CDM
All the participants were askedd to fill
fi in a project evaluation form which aimed at valorising the main aspects
of the project activity (from 1 to 5)11 and collect stakeholders concerns and expectations about the project:
project
1- Biogas valorisation from the vinasse treatment
11
The complete evaluation forms are available for DOE consultation.
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234567-
Electricity production through
t
biogas combustion
Creation of permanent and stable jobs
Stimulation of the local economy (development of new business)
Improvement of local air quality (reducing unpleasant odours)
Organic fertilizers production
Decrease of the outflow of foreign exchange
exchange capital by reducing the import of fossil fuels.
The overall response to the project was encouraging and positive. All the hearings were held in Spanish.
E.2.
Summary of the comments received:
Stakeholders were mostly curious about the CDM Mechanism
Mechanism and the Kyoto Protocol. Mr. Timothée Lazaroo
gave details on it and explained how the system works.
Other concerns involved knowing the benefits that the project will bring to the area and the surrounding
communities. Eng. José Dopeso explained that the project will:
1- reduce the methane emissions
emission released to the atmosphere;
2- reduce odours that have been affecting the surrounding communities;
3- improve the technicians and operators’
operators knowledge about this new technology;
technology and
4- have a multiplier effect on the implementation
i
of new plants similar to Varela Hermanos.
H
Some questions were asked about the type of new jobs that the project will be creating
creat
and how local workers
that could
ould be involved in this project operation would be trained. A detailed
detail response of the number of
engineers and technical
al workers to be contracted has been provided and it was explained that local workers
will be trained by UEM Group staff in a later stage.
Other participants asked how the CDM could benefit their own activities (farming, fruit growing, land use and
forestry...), and what were the specific requirements for developing CDM projects. Extensive information and
responses have been provided to the attendees in that regard.
All the explanations given during the meeting allowed the
he participants to understand that the project directly
benefits the local community.
E.3.
Report on how due account was taken of any comments received:
As stated in Sections E.1 and E.2.,
E.2., stakeholders consider the CDM project has positive impacts as a whole.
Therefore, it is unnecessary to take additional measures.
57
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Annex 1
CONTACT INFORMATION ON PARTICIPANTS IN THE PROJECT ACTIVITY
Organization:
Street/P.O.Box:
Building:
City:
State/Region:
Postfix/ZIP:
Country:
Telephone:
FAX:
E-Mail:
URL:
Represented by:
Title:
Salutation:
Last Name:
Middle Name:
First Name:
Department:
Mobile:
Direct FAX:
Direct tel:
Personal E-Mail:
Varela Hermanos S.A.
P.O. BOX 0819-07757
0819
N/A
Panama
Pana
anama
N/A
República de Panama
(507) 337-4000
337
(507) 377-4009
377
[email protected]
www.varelahermanos.com
Eng. Luis J. Varela Jr.
Executive Vice-president
Vice
Varela
José
Luis
Gerencia General
(507) 6670-8999
6670
(507) 377-4009
377
(507) 377-4003
377
[email protected]
58
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Annex 2
INFORMATION REGARDING PUBLIC FUNDING
This Project does not receive any public funding from Annex I Parties.
59
(CDM
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Annex 3
BASELINE INFORMATION
PANAMANIAN
AMANIAN GRID EMISSION FACTOR CALCULATION
Tool to calculate the emission factor for an electricity system”
system (Version 2.2.1).
Application of the “Tool
According to the tool, the Emission Factor calculation comprises the following steps:
STEP 1. Identify the relevant
levant electricity systems.
STEP 2. Choose whether to include off-grid
off grid power plants in the project electricity system (optional).
STEP 3. Select a method to determine the operating margin (OM) factor.
STEP 4. Calculate the operating margin emission factor according to the selected method.
STEP 5. Calculate the build margin (BM) emission factor.
STEP 6. Calculate the combined margin (CM) emissions factor.
Step 1. Identify the relevant electric power system
The following map shows that the Panamanian electricity
city grid is interconnected: power plants are physically
connected through transmission and distribution lines to the project activity. Therefore, the relevant electric
power system is the national grid.
Figure 9: Map of the Panamanian electrical grid.12
STEP 2. Choose whether to include off-grid
off grid power plants in the project electricity system (optional).
Project participants may choose between the following two options to calculate the operating margin and build
margin emission factor:
12
http://www.etesa.com.pa/plan_expansion.php?act=mapa
60
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Option I: Only grid power plants are included in the calculation.
Option II: Both grid power plants and off-grid
off grid power plants are included in the calculation.
Since off-grid
grid power generation plants in Panamá is not significant, Option I has been chosen for the
Emission Factor calculation. Therefore, only grid power plants have been considered. This is stated in the
paragraph 2 of the Step 2 of the “Tool
Tool to calculate the emission factor for an electricity system”
system (Version 02).
Step 3. Select a method
od to determine the operating margin (OM) factor.
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.
The Simple OM method (a) can be used when low-cost/must
low cost/must run resources constitute less than 50% of the total
amount of the power generation on the grid, in average of the five most recent years. According to Panama’s
National Dispatch Centre, the total
total electrical power generation of Panama in 2009 is 5,976 GWh, in which
hydro power generation is 3,588 GWh accounting for 60.0% of power generation (Table
(
19). Therefore, the
Panamanian generation system is dominated
dominated by hydro power. Thus, method (a) is not applicable.
Total Grid generation [GWh]
Hydro [GWh]
Share of hydro [%]
2005
5,088
3,418
2006
5,025
3,197
2007
5,517
3,324
2008
5,562
3,712
2009
5,976
3,588
67.2%
63.6%
60.3%
66.7%
60.0%
Table 19:: Share of hydroelectric production in Panama, 2005-2009.
2005
The method (b), simple adjusted OM emission factor (EFgrid,OM-adj,y) is a variation of the simple OM, where the
power plants/units (including imports) are separated in low-cost/must-run
low
n power sources (k)
( and other power
sources (j).
). Simple adjusted OM is based on data on net electricity generation of each power plant unit and on
total fuel consumption. These data are publicly available therefore, method (b) is chosen.
The method (c) requires
quires hourly fuel consumption and energy efficiency for each plant of the Panamanian grid.
To date, this data is not publicly available. Method (c) is therefore not applicable. Method (d) is not chosen by
the Project Participant.
According to the tool, for
or the simple OM, the simple adjusted OM and the average OM, the emissions factor
can be calculated using either of the two following data vintages:
• Ex ante option: If the ex ante option is chosen, the emission factor is determined once at the
validation stage,
tage, thus no monitoring and recalculation of the emissions factor during the crediting
period is required. For grid power plants, use a 3-year
3
generation-weighted
weighted average, based on the
most recent data available at the time of submission of the CDM-PDD
CDM PDD to the DOE for validation.
For off-grid
grid power plants, use a single calendar year within the 5 most recent calendar years prior
to the time of submission of the CDM-PDD
CDM
for validation.
• Ex post option: If the ex post option is chosen, the emission factor is determined
de
for the year in
which the project activity displaces grid electricity, requiring the emissions factor to be updated
annually during monitoring. If the data required to calculate the emission factor for year y is
61
(CDM
- Version 03
usually only available later than six
s months after the end of year y,, alternatively the emission factor
of the previous year y-1 may be used. If the data is usually only available 18 months after the end
of year y,, the emission factor of the year preceding the previous year y-2 may be used. The same
data vintage (y, y-11 or y-2)) should be used throughout all crediting periods.
The ex-ante option is chosen, and EFOM is fixed during the crediting period.
STEP 4. Calculate the operating margin emission factor according to the selected method.
(b) Simple Adjusted OM
The simple adjusted OM emission factor (EF
( grid,OM-adj,y)) is a variation of the simple OM, where the power
plants/units (including imports) are separated in low-cost/must-run
low
run power sources (k)
( and other power sources
(m). As under Option A of the simple OM, it is calculated based on the net electricity generation of each power
unit and an emission factor for each power unit, as follows:
Where:
EFgrid,OM-adj,y
λy
EGm,y
(MWh)
EGk,y
(MWh)
EFEL,m,y
EFEL,k,y
m
k
y
Simple adjusted operating margin CO2 emission factor in year y (tCO2/MWh)
Factor expressing the percentage of time when low-cost/mustlow
-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
Net quantity of electricity generated and
and delivered to the grid by power unit k in year y
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
t/must-run power units
All low-cost/must
cost/must run grid power units serving the grid in year y
The relevant year as per the data vintage chosen in Step 3
As low-cost and must-run
run sources are only composed of hydro in Panama, the second term of the equation
equat
above is not considered (
for hydro = 0).
Net electricity imports must be considered low-cost
low
/ must-run plants.
is defined as follows:
Lambda (λy) should be calculated as follows:
62
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- Version 03
Step i) Plot a load duration curve.
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) Collect power generation data from each power
power plant / unit. Calculate the total annual generation (in
MWh) from low-cost/must-run
run power plants / units (i.e. Σk EGk,y).
Step iii) Fill the load duration curve. Plot a horizontal line across the load duration curve such that the area
under the curve (MW times hours) equals the total generation (in MWh) from low-cost/must-run
low
power plants
/ units (i.e. Σk EGk,y).
Step iv) Determine the “Number of hours for which low-cost/must-run
low
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
ut of the total of 8,760
8 760 hours) to the right of the intersection is the number of hours
for which low-cost/must-run
run sources are on the margin. If the lines do not intersect, then one may conclude
that low-cost/must-run
run sources do not appear on the margin and
a λy is equal to zero.
Load duration curves
1 200
800
600
400
200
0
1
252
503
754
1005
1256
1507
1758
2009
2260
2511
2762
3013
3264
3515
3766
4017
4268
4519
4770
5021
5272
5523
5774
6025
6276
6527
6778
7029
7280
7531
7782
8033
8284
8535
Generation (MWh)
1 000
Hour
Total generation
Generation from low-cost/must-run
Figure 10: Load duration curve for the year 2007.
63
(CDM
- Version 03
1100
1000
900
800
700
600
500
400
300
200
100
0
1
351
701
1051
1401
1751
2101
2451
2801
3151
3501
3851
4201
4551
4901
5251
5601
5951
6301
6651
7001
7351
7701
8051
8401
8751
Generation (MWh)
Hour
Total generation
1200
Generation (MWh)
1000
800
600
400
0
1
252
503
754
1005
1256
1507
1758
2009
2260
2511
2762
3013
3264
3515
3766
4017
4268
4519
4770
5021
5272
5523
5774
6025
6276
6527
6778
7029
7280
7531
7782
8033
8284
8535
200
Hours
Total generation
Lambda values for Simple Adjusted OM Method
λ
2007
2008
2009
0.00%
0.00%
0.00%
64
(CDM
- Version 03
OM emission factor
Name of Power Plant
BLM 2
BLM 3
2007
2008
2009
Electricit
Electricit
EFEL,m,y
y
Emissions
y
Emissions
Emissions
[tCO
tCO2/MW Generati [tCO2/yea Generati [tCO2/yea 2009 [tCO2/yea
h]
on
r]
on
r]
r]
[MWh]
[MWh]
1,147
184 383
211 488
127 484
146 224 18 200
20 875
110
1,127
172 243
194 118
117 459
132 377
762
124 829
BLM 4
1,178
152 744
179 933
85 697
BLM 5 (JB5)
1,243
1 419
1 764
2 086
2 593
1 949
2 422
BLM 6 (JB6)
1,27
339
431
695
882
1 642
2 086
BLM 8
1,133
10 143
11 492
5 469
6 197
8 052
Ciclo Combinado (Ciclo)
0,684
544 457
372 408
310 197
212 175
235 513
PAN_AM
0,666
678 216
451 692
629 783
419 436
7 107
344
317
662
821
Copesa
TG Panama (PanG EGESA)
1,175
64 346
75 606
72 065
84 676 15 707
18 456
1,494
4 275
6 387
15 987
27 981
Pacora
0,672
380 969
256 011
413 264
Cativa (IDB)
0,659
0
0
69 595
23 885 18 729
437
277 713
124
488
45 863
574
Cativa II (GENA)
1,180
0
0
0
El Giral (T_Caribe)
0,746
0
0
0
2007
Total thermal generation
2 193 534
Total electricity supplied by relevant
sources
urces [MWh] (2007 + 2008 +2009)
Share of total electricity supplied by
relevant sources (2007 + 2008 +2009)
OM emission factor [tCO2/MWh]
/MWh
2008
100 951 91 775
0 61 723
126
0
788
2009
1 849 781 2 387 218
6 430 534
34%
29%
37%
0.7755
Table 20: OM Calculation
Based on 2007, 20088 and 2009, the calculated Operating Margin is: 0.7755 tCO2/MWh.
/MWh
65
108 111
441 439
293 747
321 970
72 824
94 584
(CDM
- Version 03
STEP 5. Calculate the build margin (BM) emission factor.
According to the tool, in terms of vintage of data, project participants can choose between one of the following
two options:
• Option 1: For the first crediting period, calculate the build margin emission factor ex ante based on
the most recent information available on units already built for sample group m at the time of CDMPDD submission to the DOE for validation. For the second crediting
crediting period, the build margin
emission factor should be updated based on the most recent information available on units already
built at the time of submission of the request for renewal of the crediting period to the DOE. For the
third crediting period,, the build margin emission factor calculated for the second crediting period
should be used. This option does not require monitoring the emission factor during the crediting
period.
factor shall be updated annually, ex
• Option 2: For the first crediting period, the build margin emission factor
post,, including those units built up to the year of registration of the project activity or, if information
up to the year of registration is not yet available, including those units built up to the latest year for
which information
ormation is available. For the second crediting period, the build margin emissions factor
shall be calculated ex ante,
ante, as described in Option 1 above. For the third crediting period, the build
margin emission factor calculated for the second crediting period
period should be used.
Option 1 has been chosen. Therefore, for the first crediting period, the build margin emission factor has been
calculated ex ante based on the most recent information available on units already built for sample group m at
the time of CDM-PDD
PDD submission to the DOE for validation.
The sample group of power units m used to calculate the build margin should be determined as per the
following procedure, consistent with the data vintage selected above:
above
(a) Identify the set of five power units,
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
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
gri 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%
≥20%
20% select the set of power units that comprises the larger annual electricity
generation (SETsample);
Identify the date when the power units in SET
SE sample 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).
As per above, the SETsample used to calculate the BM has been chosen, using the power plant capacity additions
in the electricity system that comprises 20% of the most recently added system generation since SET≥20%
annual electricity generation is higher than SET5-units. Moreover, none of the the power units in SETsample
started to supply electricity to the grid more than 10 years ago. Therefore, steps (d), (e) and (f) have been
ignored.
66
(CDM
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The following table shows the recent capacity additions:
additions
Generation in
Accumulated % of total
2009
generation
in GWh
2009
0
0%
Mendre
2009
127
2.12%
El Giral (T_Caribe)
2009
62
3.15%
Cativá II (GENA)
2008
489
11.33%
Cativá (IDB)
2008
19
11.64%
TG Panama (PAN G- EGESA)
2006
2
11.67%
Candela
2003
437
18.99%
Pacora
2003
303
24.05%
Esti (ESTI 1)
Table 21:: Recent capacity additions included in the BM calculation
Name of power plant
Year of
operation
The build margin emissions factor is the generation
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, calculated as
follows:
Where:
EFgrid,BM,y
EGm,y
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)
Power unit included in the build margin
Most recent historical
historical year for which power generation data is available
EFEL,m,y
m
y
The following table shows the calculated carbon emission from the power units m:
Type
Generation in
2009 [MWh]
Emission
Factor
[tCO2/MWh]
Mendre
El Giral (T_Caribe)
Cativá II (GENA)
Cativá (IDB)
TG Panama (PAN G- EGESA)
Candela
Pacora
Hydro
Motor
Combined Cycle
Motor
Gas turbine
Hydro
Motor
0
126 788
61 723
488 574
18 729
1 698
437 124
0,000
0,746
1,180
0,659
1,494
0,000
0,
0,672
0
94 584
72 824
321 970
27 981
0
293 747
Esti (ESTI 1)
Hydro
302 871
TOTAL
1 437 507
Table 22: BM Calculation
0,000
0
Power Plant
67
CO2 Emissions
[tCO2/year]
811 106
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The calculated Build Margin is: 0.5642 tCO2/MWh.
STEP 6.. Calculate the combined margin (CM) emissions factor.
The calculation off the combined margin (CM) emission factor (EF
( grid,CM,y) is based on one of the following
methods:
(a) Weighted average CM; or
(b) Simplified CM.
The weighted average CM method has been preferred. Therefore, the
he combined margin emissions factor is
calculated as follows:
EFgrid,CM,y = EFgrid, OM,y x WOM + EFgrid, BM,y x WBM
EF grid, BM,y
EF grid,OM,y
W OM
W BM
Build margin CO2 Mission factor in year y (tCO2/MWh)
Operating margin CO2 Mission factor in year y (tCO2/MWh)
Weighting of operating margin emission factor (%)
Weighting of operating margin emission factor (%)
For projects (other than wind and solar power generation): wOM = 0.5 and wBM = 0.5 for the first crediting
period, and wOM = 0.25 and wBM = 0.75 for the second and third crediting periods.
Based on 2007, 2008 and 20099, the combined margin emission factor is 0.6699 tCO2/MWh.
68
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Annex 4
MONITORING INFORMATION
No additional data to be added. Please refer to Sections B.7.1 and B.7.2 for detailed information.
69
(CDM
- Version 03
Annex 5
TABLES AND FIGURES
Table 1: Planning data for alcohol production ................................................................
.................................................................... 7
Table 2: Current anaerobic ponds characteristics ................................................................
............................................................... 8
Table 3: The digesters removal efficiencies ................................................................
........................................................................ 10
Table 4: Assessment of applicability criteria for the methane recovery component. ......................................... 15
Table 5: Assessment of applicability criteria for the electricity generation component..................................... 18
Table 6: Parameters used to determine the methane recovery component baseline .......................................... 20
Table 7: Impact of CERs revenues on the Proposed Project’s IRR ....................................................................
................................
22
Table 8: IRR fluctuation................................
................................................................................................
...................................................................... 22
Table 9: BEww,treatment,y forecast for 2013-2019.
2013
................................................................
.......................................................... 41
Table 10: BEy forecast for 2013-2019
2013
................................................................................................
................................................ 41
Table 11: PEfugitive,ww,y
ive,ww,y forecast for 2013-2019
2013
................................................................
............................................................ 43
Table 12: PEy forecast for 2013-2019
2013
................................................................................................
................................................ 44
Table 13: Emission reductions associated with methane recovery - 1st crediting period ................................... 44
Table 14: Net quantity of thermal energy supplied by the project activity .........................................................
................................
45
Table 15: Baseline emissions related to heat productiont (BEthermal,CO2,y) ..........................................................
................................
45
Table 16: Baseline emissions for
fo electricity produced from biogas (BEy,EG). ....................................................
................................
46
Table 17: Baseline emissions-Energy
Energy generation component ................................................................
............................................ 46
Table 18: Emission reductions associated with energy generation - 1st crediting period .................................. 47
Table 19: Share of hydroelectric production in Panama, 2005-2009.
2005
................................
...............................................................
61
Table 20: OM Calculation ................................................................................................
................................
.................................................................. 65
Table 21: Recent capacity additions
itions included in the BM calculation.................................................................
................................
67
Table 22: BM Calculation ................................................................................................
................................
.................................................................. 67
Figure 1: Map of Panama................................
................................................................................................
..................................................................... 5
Figure 2: The project’s location ................................................................................................
........................................................... 6
Figure 3: Vinasse anaerobic lagoons ................................................................................................
................................................... 8
Figure 4: Flow diagram
agram of the biogas digester system................................................................
......................................................... 9
Figure 5: Conceptual diagram of the boundary of the project ................................................................
........................................... 18
Figure 6: IRR fluctuation ................................................................................................
................................
.................................................................... 22
Figure 7: Pictures showing locations of the posters announcing the meeting ...................................................
................................
55
Figure 8: Scenes from the Local Stakeholder Consultation Meeting .................................................................
................................
56
Figure 9: Map of the Panamanian electrical grid. ................................................................
............................................................. 60
Figure 10: Load duration curve for the year 2007. ................................................................
............................................................ 63
Figure
ure 11: Load duration curve for the year 2008. ................................................................
............................................................ 64
Figure 12: Load duration curve for the year 2009. ................................................................
............................................................ 64
-----
70

PDD_Varela Hermanos V1 0

Transcription

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